Environmental Protection Technology Series
IMPACT OF CLEAN FUELS COMBUSTION ON
PRIMARY PARTICULATE EMISSIONS FROM
STATIONARY SOURCES
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into five series. These five broad
categories were established to facilitate further development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. EcologicaJ Research
4. Environmental Monitoring
5 Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to develop and
demonstrate instrumentation, equipment, and methodology to repair or prevent
environmental degradation from point and non-point sources of pollution. This
work provides the new or improved technology required for the control and
treatment of pollution sources to meet environmental quality standards.
E PA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/2-76-052
March 1976
IMPACT OF CLEAN FUELS COMBUSTION
ON PRIMARY PARTICULATE EMISSIONS
FROM STATIONARY SOURCES
Aerotherm/Acurex Corporation
485 Clyde Avenue
Mountain View, California 94042
Contract No. 68-02-1318, Task 17
ROAP No. 21ADK-004
Program Element No. 1AB012
EPA Project Officer: Gary L. Johnson
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ABSTRACT
The use of high-sulfur coal for large scale steam raising will be required to increase sub-
stantially in the near future. A major reduction in SCL emissions from those sources will be re-
quired to meet pertinent state and federal standards. This sulfur reduction can either be accom-
plished by desulfurizing the fuel or by removing SOg from the flue gas. Various coal conversion
processes proposed for sulfur removal were examined to determine the implications for particulate
removal requirements when the converted fuels are burned. Limited information is available on the
combustion of synthetic fuels, -but based on the data obtained and the nature of the fuels, little
problem was foreseen in meeting effluent requirements for particulates. Other factors upstream of
the combustion of those fuels seem more likely to determine particulate removal requirements, e.g.,
turbine blade erosion or methanation catalyst poisoning. The costs of sulfur removal by flue gas
desulfurization were examined briefly. The cost savings potentially obtained by elimination of
effluent particulate control systems with synthetic fuels were insignificant in affecting the sub-
stantial cost advantage of flue gas desulfurization versus fuel conversion.
-------
TABLE OF CONTENTS
Section
1 INTRODUCTION 1-1
2 CONCLUSIONS AND RECOMMENDATIONS 2-1
3 GENERATION OF SYNTHETIC FUELS 3-1
3.1 Gasification Processes 3-3
3.2 Pyrolysis Processes 3-10
3.3 Dissolution Processes 3-15
3.4 Chemical Coal Cleaning 3-19
3.5 Steam Raising Applications 3-21
4 COMBUSTION GENERATED PARTICULATES FROM SYNTHETIC FUELS 4-1
4.1 Coal-Derived Gases 4-2
4.2 Liquid Fuels 4-8
4.3 Solid Fuels 4-8
5 ECONOMICS OF COAL DESULFURIZATION 5-1
REFERENCES R-l
APPENDIX A-l
-------
LIST OF ILLUSTRATIONS
Figure Page
3-1 Potential routes for obtaining clean fuels from coal. 3-2
3-2 Coal gasification process schematic. 3-4
3-3 General schematic of pyrolysis process. 3-13
3-4 Viscosity, boiling range and grivity relationships for fuel oils
(Reference 212) with data added for synthetics. 3-14
3-5 Schematic for dissolution processes. 3-16
4-1 Data on particulate from synthetic gases. 4-5
4-2 Comparison of ash size from ignifluid and pulverized coal combustor. 4-7
4-3 Data on particulate from synthetic liquids. 4-9
4-4 Data on particulate from SRC. 4-11
5-1 Comparison of generation methods. 5-10
vi
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LIST OF TABLES
Table
3-1 Gasification processes. 3-5
3-2 Pyrolysis processes. 3-11
3-3 Dissolution processes. 3-17
3-4 Sulfur compounds in bituminous coals. 3-20
4-1 Synthetic gas uses. 4-2
4-2 Particulate size distribution from stirred bed reactor. 4-6
5-1 Processes selected for comparison. 5-2
5-2 Major design assumptions for comparison. 5-3
5-3 Major economic assumptions for comparison purposes. 5-4
5-4 Total capital investments of coal gasification and stack gas
scrubbing systems for retrofitting a 500 MW power unit. 5-5
5-5 Total average annual revenue requirements of coal gasification and stack
gas scrubbing systems for retrofitting a 500 MW power unit. 5-6
5-6 Comparison of generation methods. 5-9
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SECTION 1
INTRODUCTION
The control of air pollutants from combustion processes remains, despite the perturbations
of the energy crisis, an accepted national goal and abatement strategies are being vigorously pur-
sued. The control techniques for combustion-related pollutants can generally be divided into two
categories depending on the source of the pollutants. The origin of certain effluents, for example,
"thermally-generated" nitrogen oxides and certain types of particulate, within the combustion zone
implies that the most effective control techniques will principally involve modifications to the
combustion process. The presence of other pollutants, notably sulfur oxides, is most directly re-
lated to the amount of some contaminant present in the fuel. While combustion history may have
some effect on the state of these pollutants, the primary control techniques require removal of the
offending substances either prior to combustion or from the effluent stream. The classic example
of this latter type of control is the reduction of SO^ emissions from stationary sources. The ap-
plication of these SOy controls has engendered significant controversy because of the magnitude of
the impact on both the cost and availability of electrical energy. Large regions of the country,
principally in the Northeast and Midwest, have depended on high sulfur fuels for power generation.
To date, with a significant decrease in the availability of low sulfur fuels reducing further the
possibility of sulfur control by switching conventional fuels, the mechanism for S02 control has
been the installation of an effluent cleaning system. These systems are quite costly, both to in-
stall and operate, and have been vociferously attacked on technical grounds of effectiveness and re-
liability. Recent developments in energy technology have opened another option as an alternative to
scrubbers, namely the development of desulfurized synthetic fuels from coal.
The transformation of coal to other, more desirable fuels has a long history in Europe and
has even been under low level investigation in this country. The primary impetus for this work has
been to obtain gaseous fuels in areas where natural gas was unavailable. Generally the past efforts
have produced either fuel for area sources or feedstock for chemical processes. Little past work
has involved combustion on the large scale required for utility applications. Today the situation
has been radically altered by the recent price increases for conventional fuels and the increasing
realization that natural gas supplies in the United States are presently insufficient and unlikely
-------
to improve. The result has been a vastly increased interest in utilization of the only fossil fuel
that the United States posseses in abundance, coal. Two major constraints exist on utilization of
United States coal supplies:
• Available coal in the region of greatest need is high in sulfur content and thus, environ-
mentally undesirable
• Many present transportation and combustion facilities are designed for liquid or gaseous
fuels and conversion to solid coal combustion would be economically prohibitive
Thus, the motivation for the recent stimulus to develop synthetic fuels. Counterbalancing these in-
centives to proceed are some substantial problems inherent in the addition of a chemical processing
step in coal combustion, viz., there are substantial energy losses due to the heating and compression
required to transform the coal, the facilities required are elaborate and expensive, and there may
be major operating problems in matching supply and demand for the synthetic fuels. The result is
that the application of coal-derived fuels is still being pursued principally at the research level.
The vigorous objections to effluent scrubbing for SOX control have stimulated much interest
in synthetic fuels; however, the economics of the trade off of pretreatment versus effluent controls
are still quite speculative. One area that requires careful evaluation is the potential for trading
one pollution problem for another. This report examines one of these trade offs between pollutants
to determine the effects of combusting coal-derived desulfurized fuels on the particulate loading
of the effluent stream. To date very limited results indicate that coal-derived fuels may substan-
tially reduce particulate loadings from the levels seen in present coal-fired facilities. If so,
the elimination of effluent particulate clean up devices will provide a substantial cost savings
which may assist in making the synthetic fuels economically competitive. The evaluation of parti-
culate generation for synthetic fuel combustion in large scale industrial and utility, steam-raising
boilers formed the basis for this study. Section 3 provides background on the various synthetic
fuel processes which are presently being considered for adoption. Section 4 examines the particu-
late generation problem for alternate fuel combustion. This examination is focused on retrofit ap-
plication of desulfurized fuels to existing utility and industrial boilers as an alternative to flue
gas desulfurization. Other applications of alternate fuels such as gas turbines and combined cycles
are considered in passing. In Section 5 the economics of sulfur removal prior to combustion are
compared to the costs of flue gas cleaning in very general terms. Section 2 examines the results
obtained and draws some tentative conclusions. The conclusions are based on extremely limited data,
both on the combustion of the fuels and on the process economics, and some recommendations are pre-
sented on appropriate future activities to reevaluate these conclusions when warranted.
1-2
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SECTION 2
CONCLUSIONS AND RECOMMENDATIONS
Although the data presently available is quite sketchy on the combustion properties of de-
sulfurized fuels, it is possible to present some general conclusions and recommend activities to
provide additional data as the development of synthetic fuels proceeds. The basic questions ad-
dressed during this study were:
t "Will synthetic fuel use in steam raising applications allow elimination of effluent
particulate controls?"
• "Will this elimination of particulate controls provide a sufficient credit that fuel
desulfurization becomes competitive with flue gas desulfurization?"
The answer to the first question appears to be that effluent particulate cleanup can prob-
ably be eliminated. However the downstream particulate cleanup is replaced for synthetic fuels
by a need for extensive particulate removal prior to the combustion stage thereby eliminating much
of the anticipated cost savings. The answer to the second question is that the margin of differ-
ence between flue gas desulfurization and synthetic fuel costs for processes which have been
studied to date is so great that any savings in particulate cleanup is negligible for conventional
steam-raising applications.
More specific conclusions which have been reached in the course of this study are:
• Utility or large industrial scale steam raising applications utilizing conventional com-
bustion are not the optimum uses of synthetic fuels
• Combined-cycle power production offers potential improvements in efficiency which may al-
low synthetic fuels to be approximately competitive with flue gas desulfurization of con-
ventionally combusted coal
• Little data is presently available on the combustion of synthetic fuels derived from
coal
• Data on the particulate output from coal gasification plants is essentially nonexistent
2-1
-------
• Although combined-cycle applications of low-Btu gas are often presented as the most
likely use of synthetic fuels from coal, major problems exist in obtaining adequate
H2S and particulate removal without intolerable heat losses
• Present data on combustion of coal-derived liquids and solvent-refined coal indicates
that particulate production from these fuels can be reduced to meet NSPS levels with
further development of firing procedures
• Until full-scale plants are constructed and operated, credible data on the economics
of synthetic fuels is nonexistent
• At the present time the potential for deriving synthetic fuels from coal is being
studied to death and there is a distinct need for increasing pilot plant numbers and
sizes, and for increased large-scale experimental activity if national energy goals are
to be met
Based on the above conclusions concerning the fate of combustion-generated particulate and
appropriate control strategies, the following recommendations appear warranted:
1. Particulate generation from synthetic fuel combustion deserves continuing attention at a
low level. No substantial effort appears required to be devoted specifically to this
question as this data is a logical output from other activities.
2. The following efforts should be monitored closely and, if necessary, funded to include
particulate measurements as part of their test program
• EPRI 2 ton per hour tests on SRC at Babcock and Mil cox
• EPRI 3,000 ton (20 MW) tests on SRC
• ERDA — Pittsburgh Energy Research Center (D. Bienstock) development of a versatile
test stand for combustion of synthetic liquids and SRC
• EPA-IERL bench-scale gasifier/gas cleaning apparatus. This provides a very useful,
versatile tool for obtaining pertinent data on particulate derived from low-Btu gas
t Powerton tests on a full-scale basis, if these survive, to obtain data on use of
Lurgi gasification to feed commercial conventional boilers
3. The activity under the synthetic fuels environmental assessments presently getting
started at IERL-RTP should be followed closely to ensure that due consideration is given
to the effects of combusting the product gas.
2-2
-------
To summarize the generation of participate from coal-derived fuels appears to be a topic
which should be monitored as the synthetic fuels industry develops, but little immediate acti-
vity can be identified to increase confidence that particulate effects will not be significant.
2-3
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SECTION 3
GENERATION OF SYNTHETIC FUELS
The derivation of liquid and gaseous fuels from coal represents one of the oldest chemical
processes having large-scale application. Early uses of coal gas for space heating and lighting
were supplanted largely by natural gas in this country, but in Europe coal has been a principal
source of both gas for industrial and residential usage and gasoline for automotive fuel. With pre-
dictions of coming shortages in natural gas, synthetic natural gas generation from the United States
coal reserves has been pursued on a low level for the past 20 years. With the recent energy short-
ages, environmentally acceptable use of coal has become crucial to achieving some measure of energy
independence. The result of this cycle of inattention then vigorous stimulation has been a prolifera-
tion of proposed processes for deriving alternative fuels from coal. To date, the information on most
processes is insufficient to make detailed assessments of the feasibility of the process or the
economics of fuel production. For example, approximately 35 processes are under investigation for
gasification of coal. Of this number, two have actually been used in recent electrical power pro-
duction applications and three others have been applied to production of chemical synthesis gas.
All of this activity has occurred overseas. Two different gasification processes have been in oper-
ation in this country recently in the process demonstration unit (PDU) phase, at a throughput approxi-
mately two orders of magnitude less than the typical rate for a commercial gasification plant. Ob-
viously questions of commercial viability for gasification processes can only be answered with the
investment required to bring more of the processes to the PDU stage and to move the most attractive
schemes to commercialization. Only then can the merits of the competing processes be evaluated.
The same comments pertain to the production of liquid and solid fuels from coal where again
there are a variety of competing processes, many of recent genesis, which will have to be culled
through the scale-up procedure.
At the present time even the nomenclature of synthetic fuels production is relatively unset-
tled because of the variety of processes and because certain processes may produce gas, liquid, and/
or solid fuels. The framework utilized in this report is illustrated in Figure 3-1. For utility
and industrial stream raising, the primary fuels of interest are low and medium Btu gas and solid
3-1
-------
Gasification
Low Btu
Gasification
*^
->
Fischer-Tropsch
Synthesis
*r
Medium Btu
Gasification
Methanation
Fischer-Tropsch
Synthesi s
Major Fuel
Low (TOO - 250)
Btu Gas
Hydrocarbon
Liquids
„Medium (250 - 850)
Btu Gas
High (900 - 1000)
Btu Gas
Hydrocarbon
Liquids
Coal—
Pyrolysis
Hydrocarbon
Liquids
Dissolution
Hydrogenation
Solidification
Hydrocarbon
Liquids
Clean
Solid
Fuel
Chemical
Coal
Cleaning
Partially
Desulfurized
Coal
Figure 3-1, Potential routes for obtaining clean fuels from coal.
3-2
-------
fuel. Synthetic liquid fuels, while attractive because they are storable, are expected to find pri-
mary application as a refinery feedstock. Similarly, production of high Btu gas will entail addi-
tional costs which are probably not warranted for use as a stationary source fuel.
In the following three sections, an attempt has been made to summarize the present status of
the coal gasification, pyrolysis and dissolution processes. Section 3.4 considers briefly a fourth
method of coal desulfurization, chemical coal cleaning. For Eastern, high pyritic sulfur coal,
cleaning by chemical solvation shows substantial promise of providing a desulfurized product at
substantially less expense than traditional synthetic fuel processes. Section 3.5 then reconsiders
the various processes in terms of large-scale steam raising combustion applications and attempts to
define some generic features of a synthetic fuel source for this usage.
In coordination with the descriptions presented herein which are a composite derived from
various sources, the references have been assembled as a guide to the literature available on various
aspects of the different processes. The literature examined during this effort is tabulated by
process and by the type of information presented. Because of the increase in interest in synthetic
fuels, there has been a recent strong upsurge in literature on the various processes. Unfortunately
many of these publications are based on the same limited data sources. Until some of the large
scale pilot plants, now under construction, have gone on-stream and obtained usable information, the
data base remains largely speculative.
3.1 GASIFICATION PROCESSES
The conversion of coal to a gaseous product is probably the most extensively developed of the
synthetic fuel processes. Recent past experience has consisted largely of synthesis gas production
for petrochemical feedstocks and ammonia synthesis. There are a variety of gasifiers operating from
coal in Europe, the Middle East, India, and Africa for these applications. The only known gasifier
locations with primary purpose to produce electrical power are the combined cycle plant with Lurgi
gasifier (170) at tunen and the approximately 30 Ignifluid combination gasifier-boilers installed
throughout the world (269).
Because of the long history of gasification and the differences in end use, a variety of con-
figurations have been developed, each with certain merits. The general schematic of a gasification
plant is shown in Figure 3-2. For most applications the equipment external to the gasifier is rela-
tively standard, the wide variability among systems coming from details of the gasifier. Basically
four types of gasifiers can be identified as shown in Table 3-1.
3-3
-------
Coal
Handling
Coal
Pretreatment
N
f-4
I
Low/Medium
Btu
Gas
Methanator
Pipeline
Gas
Ash
Figure 3-2. Coal gasification process schematic.
-------
TABLE 3-1. GASIFICATION PROCESS
•Hijcui NMV
Uril
uctwjtt-Totni
Mlptler
kk)!1«>-b1iisha
Ignlflutd
Oerelooor(i)/
Spoosortl)
lurgl Nlneral-
tltechnlk MM
toppers Co..
Inc.
Caty Povwgas
Inc.
Vellnin Engi-
neering Co.
City College cf
WlT. labcock-
Atlantlqua. Ky-
tfrocarnen le-
search. Inc.,
tuafai
•races!
Producl(s)l
HM1u»'Low (to
Ess. Byproducts
«O i*1), tir
lledliixt Btu Gas,
KiWJuNl
NHIm 'I o> Btu
Cis. Byproduct:
dry ash
htdltn/Lo* ttu
01. Byproduct:
tars In gis
ion Blj lias.
Byproduct: dry
ash
SUtn of
UerflOpOWIt
Since 1936. lint 80
unlti n»e been built,
sow with MxlMN dl-
•Mttr of 12 ft tad
upiclty of SCO TW to
rroJu.r 40 > io' cro.
ItHhtnuton procesi
MS just recently de-
nlooed.
Since 1950. over SO
unltl fijko tern built.
of 3SO IPO ind produ-
ct W v 10' 11 D,
Mtntjr for imonle
tyntlwtt.
Ov^r If- pljnts have
teen built since
1926. eich giilfler
produdna a MxlHN
of M i. 10* CFO frae
400 TrO coil. f4lnly
for ao^onla. awtha-
nol. Flscher-Troplch
syn.
These gaftflers are
mw cnnierclally
In U.S.
Labaratory tests at
tun. 13 in pilot
plants at la Cor-
neuve, France, pres-
surtted tests at
Trenton. NJ. several
units In Europe.
Coal(s)'
Processed
Types 1. C,
noncaklng coals
Types A, B. C.
lignites, all
types of coal.
solid and li-
quid furls
Tyres B. C.
lignites, oils.
tars, weakly
Clklng coals
can be proceS'
sed
Bituminous coal
used In U.S.
Type C. low
sulfur coats
coal
Prepara-
tion
Coal Is crushed
ant dried
Coal Is finely
pulverlted and
dried
Crushed, drytnn
not required If
•olsture less
than 1»
Coal Is crushed a
dried tprrtreat-
«J In fluid bed
with new t 0;
Crushed and
dried
Process Date
Gasifying
Hedlue
tMSirter
Type(s)
r.u of
Char
CO
'!?'
"l
'!?'
Typical In Cas Cpatmtlep aid Properties'
"j
'S'
"2°
'8'
V
'I?
Coxnerclallted Practises
Oxygen and
stean/alr and
steaei
Oxyger and stea*
Oxygen and
steaa/alr and
steam
Oxygen and
steap/elr and
steav,
Air only
Fixed bed reac-
tor with counter-
Current contact-
Ing
HoHionul.y
llrtd tntrjlntd
t>e1 Co./OTI.
9«(-
ller; electro-
thenul/oijrgen/
ttew-tron/steu-
»ir fluid bed
Ch*r 9*i1f ter for
HI
Hwfdited bed
Utinf dolualte/
llwttone «< Ac-
cepter for HjS,
fl>2
KjUlple fluttf
bcdi «lth dolo-
•tte re9ener«tor
ttep
Part of char
fro* h>-drofias1-
f ler bwmtd In
char gasffter
Burned In
fluid. led bed
regenerator
with air at
1900'f
Chir It "tth-
4ra«n am) gts-
Ifled. then
used In dulo-
dtte ntyener*-
tlun
21. 3/
1B.O/
7.4/
13.5
14.1
17.7
I4.4/
IB.S/
7.1/
12.7
s.s
B.i
14. tl
22.B/
22.S/
16.6
44.6
11.3
17. 1/
34.4/
M.9/
U.I
17.1
7.5
I.I/
0.9/
l.S/
O.B
0.01
trace
19. »/
I4.1/
Zt.2/
n.«
17.1
2.5
o.«/
3.S/
l.O/
0.6
1.JI
— /
--/
•-/
2*.l
0.2
50.0
O.I
O.I/
O.eV
I.W
0.2
(00-
1200
1590-
1550
14m-
110}
\t&-
1U3
150-
MO
150-
240
»*;:
111!
U5i
215
aoo
US
u>
CJ1
-------
TABLE 3-1 (Continued)
fraii in*
Stirred Bed Producer
Ceglt
Pirtlll Oildatlon
Traccss
DMttonrd)/
S»o«sor(«)
Bureau of Nines
Central Elec-
tric. EP«1
Texaco Inc.
Proem
•raduct(i)1
Low Blu Git.
Byproduct: dry
• sh. lirl In
lit
Low Btu Git.
Byproduct: dry
tin
as"h end mtar
Statin of
Development
12 TPD unit In Hor-
gantoMn, V. VA MMch
produces 1.6 • 10*
CFO raw gat.
24 TPO pelng planned
for construction In
1975-77.
Conperclal un(t has
been In operation
since 1957 at Horgan-
tench section it
botton
File of
Our
4 Bed Gaslflers
Ash Is removed
through rout-
Ing grate at
bottom
Ash reiond
frM boltoai
through Moving
grate
Hoi ten slag
drops through
bottom to
quenching water
•nd moved IS
solid ish
Typical la. CIS CoemMltle* end Propertlej'
CO
'!?'
22
4S/
27.S
°>1
'5'
e
II
l.o
"2
'5'
16
4S/
2S.3
V
'IT
-/
8.5
V
'!?'
o.s
"/
trace
n4
IT
V«
'!?'
•if
")
(»l
I)
Other
va
300
300
22S
ISO
\Ui
J»'.-
l.'S
Processes either Proposed or it Pilot Plant Stage - Fluid Bed Gaslflers
Kydran.
Syntlune
union Carbide (Uli
Agglcexntlon
Coget
P1»1dlnd Bed
U-*as
U.S. Buraeu of
mats
U.S. Surt.ii of
RIMI
btltl It-Union
Cirbtde/OU,
AU
Cogat Oeveloo-
>*nt co./nc.
othtn
lllOTlnout Coil
•M«arch/OCI
Institute Of
Gil Technology
jjediu-i Btu Gat.
am. oils In
»"
Mrdtu«/lOM BtU
Coif. tt>i'roJ*Kt:
3ry" char and
otli In gas
Hedlui Btu Gas,
Byproduct: dry
am and urs In
9"
Hrdlun Btu Git.
Byproduct: dry
am or tlag,
hydrocarbon li-
quid from COBt-
parlun pyrel-
ysls step
hVJIuM/lew Vtu
Gas. typroducf:
dry asli
LMjIuGM.
Byproduct: dry
ash
Bencn scale tests
hive been coapleted;
a sMll 10 Ib/hr pi-
tot plint Is cur-
rently In operation
» 70 TPD pilot plant
to proJuve I'OO M 10'
CFO Is under con-
struction at Bruce-
ton. PA
Construction of a 2S
TPD pilot plant Has
started In late 1973
under the direction
of Chenlco to produce
1 > ID1 CFO ra. gas.
Tun pilot plints In
Princeton. It) and In
Englind. both plants
ut* char frun COED
procett, NJ plant
uses 2.S TPD and Bri-
tish plant SO TPD
(operated by BCUU).
1.2 irn unit at Hon-
raeillle. PA.
1000 TPO dnon
-------
TABLE 3-1 (Concluded)
__
•vs$r
PrOCeSS t
Praductfs)1
sutm «r
Pewl opMflt
Process Oata
C«al(s)2
MX tiied
Coal
Prepara-
tion
Gasifying
Nediuei
Gaslfler
Typed)
Fate of
Cher
C9
'5'
»2
'51
"2
(HO,
Trelcal la> Cat Ct^mltlM a«d Pni«rtln>
V
'3'
V
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•S1
V.
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•5'
*.
(tt>l
t)
ouw
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(•f)
rni.
(ni>)
wy
llu/uf)
rracaun afUnr PrwM or M HIM nut SU9I - OUalnM rlo> iallf Itrt
Ji-tal
CittralnM M
Col Mir
CmralMd M
tallfltr
PrCitljrUM £fltr«1iu4
M intfltr
[ntratiKd M
Catiriar
Bttu-fnout 0*1
Researcn, IK./
QW. AGA
CaeftustlM £•-
rlneerlng.
nc. /Consoli-
dated Cdlson.
OCfi
Babcock and
MM co*. Oupoiit/
iureaa of JMiMtt
faster. UhMlir,
PHt1ttfr$BlHi;l-
Mr, united Air-
craft, Hirthern
States Po»«K
trial** Tovno
IW»ers*ty/iX*
Htdlu.yt.ow BIH
CM, Byproduct:
TTIflfed ash
Medtu.VI.flM tUy
Gas. Byproduct:
slagged <*h
Hediup/toM fltu
ti&, Byproduct:
sITggfld «**
IQM Btu Oil.
B;prodxt:
Hl95*d ith
*tediu«Btit Ui.
Byproduci:
tl«49«d fth
120 TPQ pilot pUnt
now opera tine at
Ho«r City, PA.
(Atly 1975) to pro-
duce 2.4 i 10* CFO
raw gat, imdtr dtrtc-
tlon of St-Mrns-Jtootr
Corp.
1.8 HHt unit *t C.E..
120 TPQ plant to be
built In 197S-77.
400 TPD unit »t\ op-
cratinj at 8«1U. u.
VA, for 1 year In
1950'i. 60 TPD plant
at Btu In 1961 and
1963, Sbi ftcktftf fi-
nancial iupport for
dtoytllrtlten plant.
6 TPD pilot unit op-
erated, dtllgft Of
1200 TPD dewnitra-
tton unit currently
itndenia/
0.6 TPO pilot unit
iindtr constntc t*0n.
Ty»e« A, B, C,
caking coal)
all right
All typei of
coals can be
practised
Alt types of
coal
All types of
coal
All types of
coal
Crushed, dried
and pulmfHd.
sttaa fed with
coal
Pulverized coal
Injected with
steu
Pulverized caal
Injected with
steu and e*y-
gen/alr
Coal Is pulver-
ized and fed
fron lock hop-
pers
Coal Is pulver-
Ited and fed
Into top of re-
actor
Oxygen and
iteu/air and
stew
Oxygen and
*t9*m/»\r a no
stea*
Oxygen and
stead/air and
steaa
Air and stea*
Oiygen and
steu
T»Q-stege co-
Current* upflow
tasiffer, en-
trained bed
Entrained bed
gasiMer t>1th
two stages
entrained bed
gaslfler "UN
coMrrent flow
Down flow en-
trained bed gai-
Ifler with two
ttaoes
Downflow en.
trained bed gas-
Ifer
Ash In gas
cleared In cy-
clone and re-
cycled to Mrst
stage, ash
slagoed and re-
Oier if recy-
cled and burned.
•oit of ash Is
converted to
ml ten slag
Stagjed ath
re«o*cd frua
botton con-
tinuously
Char cofciwited
In lower stage,
anlten slag
dropped to
Quench tank
Char Is recy-
cled, gasified,
nb reaoved
as slag
n.v
23.4
/
20.1
«,2/
J7.S
J.3t
4.7
I
i.t
li.2/
S
12. 7/
21.3
/
K.I
3J.4/
39
«.o/
f.O
/
6.1
IS
o.w
0.2
/
O.S
i.i/
/
tract
0.11
2
O.U
l.S
0.3/
41.4
/
i/loM Btu
ETi. lyproduct:
dry «th *sd
Urs In oil
LM Btu Gil.
fj>V53Sen~dnF
«lh and lulfur
HkSlllM.'lPW Rtll
utt, t)>^rt*JtKt:
Try nh and
lulfur
laboratory ftattbt-
llty testt have been
•udt, a pilot plant
U planned.
A smll pilot plant
hit iweri conttncted*
the antten stlt con-
tains a renewable
tiliiyt!.
labrratorv icale foa-
ll&lMty UHt M4e
In furnace holdlna 3
twins Mdt for 1MM
pilot pUnt.
Trpei A. S. C.
all types of
cwH
Can handle
caking coal I
Typ» A. B. C.
«M tyiMl uf
coal
Cruthed and
dried coal
jskkea up from
lock hoppers by
prt>nrjti-d stea*
«mJ t*ftjrvcit/*lr
and fed to gasf-
Mrr with KA2C03
Coil MU%C be
cru-.hnl antf
dried
Coal U cn.ihf^
ity Jr li'J tM
InjKletf «ttn
iti-i-^ tf pollen
Ircn tMth
Oxygen and
stea*/a1r and
ste»
Air In gaslfler
Onyqen and
itr*«/*lr *cj
siva*
ttohen v«U
gaslfltr with
Hied bed
Nolten talt
gaslfler
Nolttn Iron bath
wltli IlMiliXte
Slag on top to
A»h 1$ removed
fro* neU purge
*»d itH U re-
covered and
rt cycled
SodliM tarbo«
nate regene-
rated and re*
cycled, ash and
sulfur removed
Slag is de.ul-
furl/eJ «R>t *\ft
fi reaeved, de-
ls recycled
Z6.II/
J8.6
M.5/
»
1».J/
) 4
J4.»/
15.0
35 O/
It
«.»/
O.l/
!.•/
2.;
o.w
SO.l
O.S/
Si
1)00
1700-
1100
2SOO
l»0
7S
20
110/
1U
us/
I4S
-------
NOTES TO TABLES 3-1, 3-2, and 3-3.
types (A, B, C, and D) refer to the classifications shown below: (Data from References 18 and 153-155)
to
co
Type
and Medium Vola-
B Interior Pro-
vince High and
Morl-inm VnlaHla
Bituminous
vlnce Sub-
D. Great Plains
Province
Lignite
Typical
Source
Indiana Co., PA
Pike Co., Eastern KY
Sewell Seam, WV
Williamson Co., IL
No. 6 Seam, IN
Vermilion Co., IL
Mussel shell Co.. MT
Sheridan Co. , MY
San Juan Co. , NM
Mercer Co. , ND
Vola tiles
(wt *)
23.4
36.7
25.0
36.2
36.6
38.8
32.2
30.5
31.0
26.6
Fixed
Carbon
(wt »)
64.9
57.5
66.8
46.3
42.3
40.0
46.7
40.8
34.0
32.2
Analysis
Ash
(wt X)
10.2
3.3
5.1
11.7
8.7
9.0
7.0
3.7
22.0
4.2
Moisture
(wt X)
1.5
2.5
3.1
5.8
12.4
12.2
14.1
25.0
13.0
37.0
Sulfur
(wt 1)
2.2
0.7
1.3
2.7
2.3
3.2
0.4
0.3
0.8
0.4
High
Heating Value
(Btu/lb)
13,800
14,480
14,290
11,910
11,420
11,340
11.140
9.350
8,900
7,610
Trace
Component
Arsenic
Beryllium
Cadmium
Chromium
Cobalt
Fluorides
Lead
Mercury
Nickel
Selenium
Tin
Vanadium
Zinc
Components
Concentration
(ppm)
10 -50
1 -3
?n fin
0.1-1
10 -20
3-8
in 9n
50 - 100
4-10
0.1 -0.3
10 30
0.5 -4
0.1 -1
10-30
4-60
Primary process products are underlined. Other listed products are produced in substantially smaller quantities.
All compositions, unless otherwise shown, are on a dry basis. Heating values are higher heating values, also on
a dry basis.
-------
Fixed Bed Gasifiers
This is the traditional form of gasifier. This category is extended to include rotating and
stirred bed reactors. Since Lurgi gasifiers are considered in this classification, this is probably
the type of gasifier with the most extensive operational background. Characterized by percolation
of input streams of gases (steam, air, and/or oxygen) through a relatively stable bed of large dia-
meter coal. Coal is fed from top and ash mechanically removed from bottom. Relatively small amounts
of particulate in product gas, but large quantities of tars and condensibles. Substantially con-
strained by caking properties of coal (may require coal pretreatment). Unable to accommodate coal
fines which must be briquetted or utilized elsewhere.
Fluidized Bed Gasifiers
Probably the largest variety of different designs are included in this category as schemes
differ substantially on injection point for both coal and input gases, bed material, number of beds,
and method of heating the bed. Fluidized beds can handle caking coals althrough they may pose some
operational problems. Coal pulverized generally to about 0.05 to 0.1 inch diameter is reacted in a
fluidized bed (or series of beds). Product gas and elutriated fines leave the top of the bed and
ash is removed from the bottom. The elutriated fines may pose particulate problems, but are generally
of a size (>20 y) easily removed by cyclones. Some versions of fluidized beds are run at tempera-
tures which result in the ash agglomerating into even larger components, thereby simplifying collec-
tion.
Entrained Flow Gasifiers
The entrained flow gasifier probably represents the category with the largest potential for
problems with particulate carryover operating as t;hey do in a manner quite similar to direct combus-
tion of pulverized coal. These gasifiers operate by entraining with a portion of the reactant gases
coal which has been pulverized to about 70 percent less than 200 mesh (comparable to pulverized coal
for direct combustion). The reactor vessel is sized and reactant injection staged to effect the
proper environment for gasification of the suspended coal particles. Classically the reactor has
been run quite hot (~3300°F) which converts the ash to molten slag. The ash removal process is quite
analogous to wet bottom pulverized coal combustion with approximately 50 percent of the ash being
removed to a water quench via a slag tap in the bottom of the reactor and the remainder being car-
ried in the product gas stream. Ash removal techniques for the product gas stream vary substantially
based on the anticipated end use of the gas. There are a variety of features of the entrained flow
gasifier which may favor its use for steam raising applications. These include:
3-9
-------
• Ability to handle caking coals without pretreatment
• High operating temperatures which burn the tars and higher hydrocarbons to CO and hL
• Ability to respond quickly and precisely to load changes
• Similarity to present pulverized coal combustion for steam raising
Based on these advantages, it is unsurprising that both Combustion Engineering and Babcock
and Wilcox have chosen to participate in development of entrained flow gasifiers.
Molten Bath Gasifiers
The final category of gasifiers and, by far, the most speculative is the molten bath. These
operate by use of a molten bath reactor which reacts the sulfur with the bath material, either potas-
sium carbonate or iron in proposed versions, thereby eliminating downstream HgS removal equipment.
There is little information on the processes generally and nothing on particulate production. It
may be useful to speculate based on the results from basic oxygen furnaces that particulate gener-
ated from the bath material may prove to be both extremely noxious and extremely difficult to remove.
3.2 PYROLYSIS PROCESSES
If the basic gasifier processes are operated at somewhat lower temperatures (~1100°F) in the
reactors, then it is possible to obtain a liquid/gas mixture as the product. This is essentially
the foundation of the pyrolysis family of coal conversion processes which include the COED, TOSCOAL,
and Garrett processes listed in Table 3-2. A conceptual sketch of the process is shown in Figure 3-3.
As indicated in that sketch, solid, liquid and gaseous products are produced. Some alteration in
product mix is feasible through operational manipulations of temperature, pressure, and reactant in-
puts. Depending on the process, all forms of coal can be handled. In addition, pyrolysis processes
have been used to recover oil from oil shale and municipal solid waste.
In general, the liquid product from these processes will be refined to optimize the mix of
gasoline, fuel oil, etc. The resulting liquids should be virtually indistinguishable from the cor-
responding products from natural crude and it is anticipated that the combustion properties of cor-
responding synthetic and natural fractions will be quite similar. One major consideration which may
perturb the particulate production from the synthetic liquids is the presence of ash and/or coal
particles which have passed through the filter. Filteration of syncrudes has proven to be a major
problem area for both pyrolysis and dissolution processes. As is shown in Figure 3-4, viscosity of
representative syncrude produces is fairly high and effective filtration can be expected to range
3-10
-------
TABLE 3-2. PYROLYSIS PROCESSES
Process Name
Devel oper ( s )/ Sponsor ( s )
Status of Development
Process
Ha fa
UQ lo
Typical
Product
Compositions
And
Properties
Coal(s) Processed1
Coal Preparation
Pyrolysls Process
Process Products*
Oil
Gas
Before
Clean-
up
Char
API Gravity
@ 60°
Viscosity @
100°, CS
S, wt. X
0, wt. %
N, wt. X
H, wt. X
C, wt. X
Moisture,
wt. X
Ash, wt. X
Metals, ppm
HHV, Btu/
scf
N2, vol X
CO?, vol X
CO, vol X
HZ, vol X
CH4, vol X
CgHg, vol X
HgS, vol X
Other, vol X
HHV, Btu/lb
C, wt X
H, wt X
N, wt X
S, wt X
0, wt X
Ash, wt X
Other, wt X
Other
COED
FMC Corp. /OCR
Process under development
since 1962, 36 TPD pilot
plant at Princeton, N.J.
1n operation, commercial
plant being designed by
R. M. Parsons Co. /OCR,
combustion of char to form
medium Btu gas under de-
velopment (COGAS).
Types A, B, & C. process
can handle agglomerating
coals.
Coal 1s crushed & dried.
Coal is heated to suc-
cessively higher tempera-
tures 1n a series of 4-
fluidized bed reactors
( 600-1 600-F. 20-25 psia),
volatile products pass to
recovery system for re-
covering oil & cooling
the gases, steam & oxy-
gen fed to 4th stage.
Synthetic crude oil.
ammonia, HjS, pyro lysis
gas, process liquors
20-25
4-8
0.1
1.5
0.2
11.0
87.1
0.1
<0.01
10.0
305.0
6.0
29.2
14.2
38.7
9.0
0.9
1.1
0.9
11,000-12,000
77.0
1.0
1.2
2.5
1.2
17.0
0.1
NHs from hydrotreatlng of
oil, process liquors from
hydrotreatlng £ pyrolysis
steps, HgS from pyrolysis
gas clean-up.
Toscoal
Oil Shale Corp.
25 TPD pilot plant at Golden,
Colo, uses coal, 1000 TPD
semi-works for oil shale at
Grand Valley. Colo., 66,000
TPD commercial plant being
designed for oil shale.
Low sulfur, non-caking coals
only, Type C coals.
Coal is crushed, dried, &
preheated with hot flue
gases.
Coal is pyrolyzed at 800-
1000°F in a drum of hot
ceramic balls, char is
separated from balls, and
pyrolysis vapors are con-
densed & fractionated, gas
used as fuel in ball heater
& coal preheater, or drawn
off as fuel.
Oil , char. gas. water
vapor
6-13
60-70
0.2
9.3
0.7
8.7
80.9
0.1
0.1
-
630.0
-
36.4
18.4 .
7.8
24.9
4.4
0.3
7.8
12,000-13,000
77.5
2.9
1.3
0.3
8.3
9.7
-
Water vapor obtained
from pyrolysis gases.
Garrett
Garrett Research &
Development Co., Inc.
0.036 TPO lab scale unit has
been in operation since
1973, 0.6 TPD pilot plant is
currently operating at La
Verne, Ca.
Type 8, C coals, process may
be able to handle caking
coa I s .
Coal is crushed & dried.
Coal is conveyed to entrained
bed carbonizer by recycled
gas & heated by recycled char
to 1100°F, char is separated
in cyclone & part is burned
in char heater, gases &
liquids are separated & tar
can be hydrotreated to pro-
duce synthetic crude.
Tar, char, pyrolysis gas,
H2S
-10 to -7
1600
0.6
0.8
1.6
4.3
92.7
-
625.0
-
9.1
22.4
35.3
18.8
-
14.4
12,000
74.0
1.9
1.0
0.6
3.9
18.6
-
H?S from pyrolysis gas
clean-up.
3-11
-------
NOTES TO TABLES 3-1, 3-2, and 3-3
Coal types {A, B, C, and D) refer to the classifications shown below: (Data from References 18 and 153-155}
ro
Type
A. Appalachian High
and Medium Vola-
tile 81 luminous
S. Interior Pro-
vince High and
Medium Volatile
Bituminous
C. Mountain Pro-
vince Sub-
bituminous
0. Great Plains
Province
Lignite
Typical
Sou re*
Indiana Co. . PA
P1ke Co., Eastern K¥
Sewell Seam, WV
Williamson Co. , IL
No. 6 Seam, IN
Vermilion Co. , R
Mussel shell Co., KT
Sheridan Co. , MY
San Juan Co. , NH
Mercer Co. , HO
Analysis
Volatile!
(wt »5
23.4
36.7
25.0
36.2
36.6
38.8
32.2
30.5
31.0
26.6
Fined
Carbon
<»t t)
64.9
57.5
66.8
46.3
42.3
40.0
46.7
40.8
34.0
32.2
Ash
<«t J)
10.2
3.3
5.1
11.7
8.7
9.0
7.0
3.7
22.0
4.2
Moisture
(*t 1}
1.5
2.5
3.1
5.8
12.4
12.2
14.1
25.0
13.0
37.0
Sulfur
(«t *)
2.2
0.7
1.3
2.7
2.3
3.2
0.4
0.3
0.8
0.4
High
Heating Value
(Btu/lb)
13,800
14,480
14,290
11.910
11,420
11,340
11.140
9.350
8,900
7.610
Trace Components
Component
Arsenic
Beryl HIM
Boron
Cadmium
ChromiuB
Cobalt
Copper
Fluorides
Lead
Mercury
Nickel
Selenium
Tin
Vanaalua
Zinc
Concentration
(Ppn)
10-50
1 - 3
20 -60
0.1-1
10 - 20
3-8
10 -20
50 - 100
4-10
0.? -0.3
10-30
0.5 -4
0.1 - 1
10-30
4-60
Primary process products are underlined. Other listed products are produced 1n substantially smaller quantities.
All compositions, unless otherwise shown, are on a dry basis.
a dry basis.
Keating values are higher heating values, also on
-------
§
3
to
1
Coal
Pretreatment
*
Product
Char
Reactor
0100 F, 20 psiq
i
Char
Combustor
T
Steam
Air/Oxygen
Gas
Separator
Gas
Product
Product
Gas
Figure 3-3. General schematic of pyrolysis process.
-------
o
o
CO
I
Ik
0
UJ
9
5 900
2
|TOO
5
2 500
•J
* 100
100
A. P.I. GRAVITY
00
1 fc 1 1 Si
1* J L. J
l*'*1 I*"'*!
r» 1 1 «4i
r- o
••
— «•
1
MOTOR ~»
- 0ASOUNE
MM^HMI
i i i nun
I
L
^
9
(0
r
/
:
f
^
^
s
^
r
»
•*
i
!
C4
5
°. n
r^-lr^H
<•
d
X
j
d
*•«%•• ^«
* A
1 8 j L -
- -
••^ »^ »_ J> ^ -
l~* ~" "
1
1
(I
li
1
»
i
LOW 9ULFER NO. 6
^^^.
i i i nun i i iiimi i i i nun i i IMIII
O.I
10 100 1000
KINEMATIC VIC08ITYAT 100°F.,CENTI8TOKES
O
CM
t-i
I
IOOOO
Figure 3-4. Viscosity, boiling range and gravity
relationships for fuel oils (Reference 212)
with data added for synthetics.
-------
from difficult in the case of the COED product to virtually impossible in the case of the Garrett
tar fraction. This problem can be expected to be most troublesome in the case of the pyrolysis
process for two reasons:
• Pyrolysis does not directly involve hydrogenation so that control over product viscosity
is more limited
• The pyrolysis process works at pressure levels near atmospheric (10 to 20 psig) as op-
posed to dissolution processes which operate at 1500 to 3000 psi allowing considerably
more margin for pressure drop through a filter
Thus, inorganic matter in the product liquid may represent a significant problem for operational
pyrolysis plants.
It should be noted that the pyrolysis process does not solve much in the way of sulfur in
the fuel. The char and liquid fraction may retain sizable percentages of their original sulfur
contaminants. While a hydrodesulfurization plant will remove the sulfur in the liquid, the char re-
mains a problem. Solutions proposed include gasification or fluidized bed combustion of the char.
3.3 DISSOLUTION PROCESSES
The dissolution of coal and its subsequent recovery as liquid and/or solid product are much
more akin to hydrodesulfurization of oil than to the classic gasification and/or pyrolysis processes.
The basic process as sketched in Figure 3-5 consists of slurrying the crushed coal with a coal-
derived solvent. This mixture then is treated with hydrogen in a warm (800°F), high pressure (-2000
psi) reactor in the presence of a catalyst such as cobalt molybdate. The resulting gas, liquid, and
solid mixture is separated. The gas is cleaned of FLS and recycled. The solids are either recycled
to the slurry or disposed of since they are anticipated to be primarily the inorganics from the
coal. The liquid is distilled into two components, a light fraction which is largely recycled as
the solvent for the slurry and a heavy fraction which is the product. The nature of the product
fraction varies among processes as indicated in Table 3-3. Depending largely on the amount of hydro-
gen added, the product may range from a solid, solvent refined coal, to a syncrude liquid with API
ratings in the 50° range. Also dependent on the amount of hydrogen and the operating conditions is
the efficiency of sulfur removal. Pyritic sulfur is removed relatively routinely. Fortunately,
pyritic sulfur dominates in most high-sulfur, Eastern and Midwestern coals, so that products of dis-
solution processes will meet NSPS standards.
Strong interest 1n solvent refined coal for use in steam raising applications has been seen
recently. This can be attributed to a combination of relatively favorable economics (more favorable
3-15
-------
CO
I
en
Coal
Coal
Preparation
Slurry
Mixer
Preheater
Solids
Light (Anthracene) Oil
Hydroaen
Separation
I
Gas
Reactor
I
Fi1tration
I
Distillation
T
Heavy Fraction
(Oil or SRC)
.Product
Gas
o
o
in
CM
Figure 3-5. Schematic for dissolution processes.
-------
TABLE 3-3. DISSOLUTION PROCESS
Process
Name
Consol
CSF
H-Coal
Synthoil
SRC
(Solvent
Refined
Coal)
Developer (s)/
Sponsor(s)
Consolidation
Coal Co. /OCR
Hydrocarbon
Research. Inc./
OCR. EPRI,
Ashland 011.
ARCO, Sunoco,
Std. 011 (Ind.)
U.S. Bureau of
Mines
Pittsburgh &
Midway Coal
Mining Co./So.
Services.
EPRI. OCR.
Wheelabra tor-
Fry e
Status of
Development
20 TPD pilot plant was
built In Cresap. W. Va. In
1967 & shut down In 1970.
possible start-up again In
near future by Fluor
Corp. /OCR
0.05 and 3 TPD units have
been In operation at
Trenton. N.J., design &
construction of 600 TPD
plant just getting under-
way, start-up estimated
In 3 years
0.5 TPD unit currently 1n
operation, 10 TPD pilot
plant also being designed,
Start-up 1976, 700 TPD
pilot plant to be con-
structed starting 1977,
10 TPD pilot plant to be
constructed by Foster
Wheeler
6 TPD unit operating at
Hllsonvllle, Ala. since
1974 under direction of
Catalytic, Inc., 50
TPD pilot plant at Ft.
Lewis, Wash. Started up
Oct. '74 under direction
of Rust Cmjni. * Str.irns-
Roger, 1000 TPD plant to
be built soon by Wheel a-
brator-Frye
Process Data
Coal(s)
Processed1
Type A,
caking coals
can be pro-
cessed
Types A & B,
caking coals
can be pro-
cessed
All types of
coal can be
processed
All types can
be processed
Coal
Preparation
Coal 1s crushed
& s lurried 1n
solvent & pre-
heated
Coal 1s crushed
& slurried 1n
recycled oil,
then preheated
Coal 1s crushed,
dried & slurried
In recycled oil,
then preheated
Coal 1s pulver-
ized & slurried
with recycled
solvent & pre-
heated
Liquefaction
Process
Sol Ids are separated from
slurry, & liquid treated
with hydrogen 1n fluid bed
catalytic reactor, solvent Is
separated from product & re-
cycled, solids are cracked to
yield char & distillates, char
1s used to produce hydrogen
Slurry 1s fed to ebul Hated
catalytic reactor with H2,
liquid product 1s flashed to
lighter & heavier components,
part of bottoms Is recycled
for slurrylng, off gas 1s
condensed partially & uncon-
densables sent to gas clean-up,
char & oil can be used as fuel
or recycled for pyrolysis
Slurry is fed to fixed bed
catalytic reactor with H2 &
recycled gases, then Into
high pressure liquid-gas
separator, gases purified &
converted to H2 & recycled,
liquids separated from solids,
char is pyrolyzed & gases sent
to H2 gasifler.
Slurry Is pumped with H? to
dlssolver at 825°F, effluent
is separated, undlssolved
solids are removed from
liquid stream & filtrate
flashed, overhead solvent Is
recycled & bottoms form sol-
vent refined coal at 300 "F,
gas & gasified sol Ids are
recycled for H2 source.
Process-
Products2
Synthetic
crud_e_fuel_
6'flV nap'h-
tha, fuel
gas, sul-
fur, ash
Synthetic
crude oil
fuel gas,
sulfur,
ammonia,
ash
Fuel oil.
ammonia,
HoS, ash,
H20
Solvent
refined
coal, sul-
fur, char
residue,
light
hydrocar-
bon liquids
Typical Product Characteristics3
Fuel oil produced Is 1.5 bbl/ton coal, 6.3 x 10'
Btu/bbl, 10.3°API. 0.1X sulfur. 0.5 bbl of
naphtha produced per ton of coal, 5.1 x 10'
Btu/bbl. 50°API. 0.06X sulfur. 3400 scf fuel
gas/ton of coal, 930 Btu/scf heating value for
cleaned gas. 71 Ib sulfur/ton of coal removed
from gas. 214 Ib ash/ton coal from gasifier
producing hydrogen.
0.4 bbl of naphtha produced/ton of coal & 1.8
bbl of fuel oil produced per ton of coal, API
gravity 4-50°, 0.15-0.45S sulfur, 0.6-1.01
nitrogen. 37 Ibs of sulfur removed from gas/
ton of coal. 229 Ibs of ash from char gasifier/
ton of coal. Anmonia also removed from fuel
gas. 1000 Btu/scf heating value of fuel gas.
3.3 bbl of fuel oil produced/ton coal, oil -
0.3% sulfur in oil. 16,000-18,000 Btu/lb HHV,
1-3% ash, 0.2% nitrogen, 20-200 SSF viscosity
at 180°F, -8 to -5 "API gravity. 101 Ib H2S
S NH3 from gas cleanup/ton coal. 300 Ib ash
residue produced /ton of coal. Water rexoved
from gas before recycle to H2 gasifier.
Composition of SRC:
C 88.2 wt X
H 5.2 wt X
N 1.5 wt X
S 1.2 wt X
0 3.4 wt X
Ash 0.2 wt X
Other 0.3 wt X
Heating value of SRC • 16,000 Btu/lb.
54 Ibs light hydrocarbons produced/ton of
coal. 142 Ibs char residue from filter
cake gasifier. 64 Ibs of sulfur from gas
cleanup/ton of coal.
CO
-------
CO
00
NOTES TO TABLES 3-1, 3-2, and 3-3
Coal types (A, B, C, and D) refer to the classifications shown below: (Data from References 18 and 153-155)
Type
A. Appalachian High
and Medium Vola-
tile B1 luminous
B. Interior Pro-
vince High and
Medium Volatile
Bituminous
C. Mountain Pro-
vince Sub-
bituminous
D. Great Plains
Province
Lignite
Typical
Source
Indiana Co., PA
Pike Co.. Eastern KY
Sewell Seam, UV
Williamson Co., IL
No. 6 Seam. IN
Vermilion Co., IL
Musselshell Co.. MT
Sheridan Co., UY
San Juan Co. , NM
Mercer Co. , ND
Analysis
Vola tiles
(wt X)
23.4
36.7
25.0
36.2
36.6
38.8
32.2
30.5
31.0
26.6
Fixed
Carbon
(wt X)
64.9
57.5
66.8
46.3
42.3
40.0
46.7
40.8
34.0
32.2
Ash
(wt X)
10.2
3.3
5.1
11.7
8.7
9.0
7.0
3.7
22.0
4.2
Moisture
(wt X)
1.5
2.5
3.1
5.B
12.4
12.2
14.1
25.0
13.0
37.0
Sulfur
(wtX)
2.2
0.7
1.3
2.7
2.3
3.2
0.4
0.3
0.8
0.4
High
Heating Value
(Btu/lb)
13.800
14,480
14,290
11,910
11.420
11,340
11,140
9.350
8.900
7.610
Trace Components
Component
Arsenic
Beryl Hun
Boron
Cadmium
Chromium
Cobalt
Copper
Fluorides
Lead
Mercury
Nickel
Selenlun
Tin
Vanadium
21 nc
Concentration
(PPOl)
10 -50
1 -3
20 -60
0.1 -1
10-20
3-8
10 -20
50 -100
4-10
0.1 -0.3
10-30
0.5-4
0.1 -1
10-30
4-60
Primary process products are underlined. Other listed products are produced 1n substantially smaller quantities.
All compositions, unless otherwise shown, are on a dry basis. Heating values are higher heating values, also on
a dry basis.
-------
than other nongaseous synthetics), capacity for storage, and the minimal nature of modifications
required to burn the SRC in conventional boilers. The combustion properties of SRC are being ex-
tensively tested under sponsorship of the Electric Power Research Institute as will be discussed
later.
3.4 CHEMICAL COAL CLEANING
Considerable activity has also been devoted recently to processes for removing the pyritic
sulfur from coal. The motivation for this effort is shown by Table 3-4 which indicates that an ex-
tensive spectrum of Eastern high sulfur coals may be utilized if a large fraction of the pyritic
sulfur is removed. Classic coal treatment, washing and hand picking, remove the largest chunks of
pyrites, but do not come close to removing enough to meet standards. Even recent developments in
gravity separation of crushed coals are inadequate to get the sulfur level down to the 1 percent
level (252). Recently, however, two processes have been proposed which are intermediate in complex-
ity between solvent refining and simple gravity separations which do promise to remove enough pyritic
sulfur to meet federal standards. The more extensively examined of the two processes is the "Meyers
process" developed by TRW Systems Group under EPA contract (139, 188, 189). This leaches the pyritic
sulfur out by immersing crushed coal (~10 to 100 mesh) in a warm (~250°F) bath of ferric sulfates
for periods of 1 to 2 hours. The ferric sulfate is regenerated and reused and elemental sulfur
recovered. The process has demonstrated removal rates of up to 95 percent at bench scale with loss
in Btu value of less than 1 percent (189). Scale-up to an 8 ton per day process development unit
is presently under way with support of the EPA.
The second promising coal treatment is the Battelle Hydrothermal Coal Process being developed
by Battelle under internal funding (247). This process also uses a leach bath which is maintained
at elevated temperature and pressure for extended periods. The coal size is 70 percent less than
200 mesh and the leachant may be either sodium hydroxide or calcium hydroxide. Details on the pro-
cess are sketchy at this date, but removal of over 90 percent of the pyritic sulfur and 30 to 40
percent of the organic sulfur is claimed. Cost estimates for this process are in the range of $10
per ton. Extensive investigation is in progress at the present time aimed at further refinement of
the process.
Both chemical coal cleaning methods may remove significant fractions of the coal ash, in the
course of desulfurization. No significant alternations in combustion properties of the refined coal
are expected and present plans envision use of existing boiler equipment. The amount of particulate
production appears unlikely to change significantly and classic effluent particulate removal equip-
ment will be required.
3-19
-------
TABLE 3-4. SULFUR COMPOUNDS IN BITUMINOUS COALS
(Data from Reference 139)
CO
i
IN5
O
Type
Pittsburgh Seam
Lower Kittaning
Illinois #5
Herrin #6
Total
Sulfur
1.88
4.29
3.48
3.80
Pyritic
Sulfur
1.20
3.58
1.57
1.65
Sul fates
0.01
0.04
0.05
0.05
Organic
Sulfur
0.68
0.67
1.86
2.10
-------
3.5 STEAM RAISING APPLICATION
Based on the information on the processes presented earlier, it is possible to make some
general comments on use of synthetic fuels for large-scale steam raising, at least in the near-
future. The use of certain fuels for this type of stationary source application can be eliminated
on an economic basis. This is most true of high Btu gas where the only large steam-raising appli-
cation might be for utility boilers which were initially designed to operate on high grade fuels,
distillate or natural gas. Even here the economics of SNG use would be extremely shaky. Similarly
at the present time, use of liquids for these applications appears relatively uneconomical. The
production of hydrocarbon liquids is attractive since they can be refined to a distillate fuel
interchangable with natural thus essentially eliminating boiler modifications. From an operational
point of view liquids are favored because they can be easily stored so dynamic coupling between
gasifier and boiler is not required. However the cost per million Btu for liquids is not competi-
tive with low Btu gas. Solvent refined coal may offer many of the advantages of liquids at costs
comparable to the producer gas. The economics however still favor the gas product based on data to
date. Other solid products from chemical cleaning are still far too speculative to be considered
at this time.
The selection of fuel thus narrows to making two basic choices:
• Low (<200) or medium (-300) Btu gas
• Hot or cold cleanup of the gas
Any of these combinations probably implies that the gasifier and combustion unit will probably be
directly coupled and physically adjacent. The combined facility will probably operate best in a
base load mode with the full unit going in and out of service together. The actual choice of the
above conditions will only be determined as the units are built to full scale. Economic assessments
must be made to determine whether complications in combustion systems using low Btu gas justify the
cost of the oxygen plant required for the medium Btu gas. The second decision between hot and cold
clean awaits the hot cleanup technology for both JUS and particulate. Hot cleanup is being inten-
sively examined but still probably is a decade away from commercial operation. Obviously scheduling
of gasifier development, as well as relative economics, will determine whether hot cleanup is used.
3-21
-------
SECTION 4
COMBUSTION GENERATED PARTICIPATES FROM SYNTHETIC FUELS
The topic of combustion properties of the synthetic fuels derived from coal has received lit-
tle recent attention. Much work was done early in the century on combustion of manufactured gases,
both in this country and in Europe. These efforts, at least in the U.S., were largely ended
by the increasing availability and use of natural gas. Recent programs for the development of syn-
thetic fuel processes have generally terminated at the creation of the fuel. Some limited results
have been obtained on the combustion properties of specific fuels, primarily COED liquid product
and solvent refined coal. These instances have usually focused first on the properties of interest
in designing combustion equipment and only secondarily on the nature of potential pollutants. De-
spite the lack of useful data to date, it is possible to make some useful generalizations on the po-
tential for pollutants from synthetic fuels combustion.
Obviously, the primary pollutant of interest to the synthetic fuels processes to date has
been sulfur. The sulfur problem has provided the impetus for continuing development of these pro-
cesses and is well below anticipated standards for most processes. Only when the chemical coal
cleaning processes and possibly solvent refined coal are compared against extremely restrictive
state-mandated S02 levels is there a possibility of a sulfur problem. The questions of NO and
particulate in the effluent are substantially less clear.
For both oil and coal combustion, chemically-bound nitrogen contributes a substantial frac-
tion of the total NOX output (References 79 and 182). In general the liquid and solid synthetic
fuels will retain a significant fraction of the -1 percent nitrogen in the feed coal. Thus, NO
control strategies for these fuels may require very careful consideration. Until full scale com-
bustion tests are attempted, it is not really possible to determine the true interaction between
the significant quantities of fuel nitrogen with the changes in combustion techniques dictated by
the new fuels. Until then the magnitude of the NO problem will remain problematic. The NO situ-
* X
ation has been explored in some detail for producer gas combustion and indications to date are that
NO does .not pose a major problem (Reference 182).
-------
The final major pollutant of interest and the specific topic of this study is particulate.
Particulate emissions from combustion processes can be considered to consist of two generic types:
• Ash carried through the combustion process from the fuel
• Unreacted carbon from incomplete oxidation in the combustion zone, including soot, ceno-
spheres, and unburned hydrocarbons
Control techniques for the latter forms of particulate are based on adjustment of the combustion
process to ensure complete carbon burnout. Until extensive tests are performed in realistic scale
facilities, it will be difficult to assess these adjustments, however some generalizations may be
possible. The ash carryover problem is somewhat more straightforward with the bulk of the ash input
to the burner passing on through with perhaps an intermediate stop as a deposit on the boiler tubes.
The various types of synthetic fuels and their potential for production of ash will be discussed
below.
4.1 COAL-DERIVED GASES
By far the greatest interest in coal conversions has focused on gasification. To date there
is no firm data on the combustion of product gases in large-scale stationary sources although the
question is being examined in increasing detail these days. Three scenarios for gas utilization
must be considered as listed below in Table 4-1.
TABLE 4-1. SYNTHETIC GAS USES
Case
1
2
3
Gas Quality
High Btu
Low - Med Btu
Low - Med Btu
HHV
Btu/scf
-1000
100 - 300
100 - 300
Purification
Temperature
Low
High
Low
Application
• Area source fuel
• Petrochemical feedstock
• Combined cycle power
generation
• Direct firing
• Single cycle firing
• Direct firing
It is possible to eliminate from further consideration Case 1 immediately since there appears
to be no reason why those should be a particulate problem, even if high-Btu gas were to be used in
steam-raising applications. Particulate removal constraints will be determined by their adverse
effects on methanation catalysts and the possibility of erosion of compression equipment. The com-
bustion properties of the synthetic gas should be no different than natural gas which does not create
particulate under normal combustion conditions.
4-2
-------
The problems associated with Cases 2 and 3 are substantially less certain. Theoretical and
experimental investigation have been conducted to determine the combustion properties of low-Btu
gas in both gas turbines and direct-fired boilers. Results for both gas turbines (References 168,
215, and 229) and direct firing (References 126 and 182) Indicate that combustion can be maintained
adequately within basic combustion region envelopes. In both Instances present indications are that
gas with a heating value in the 300 Btu range is highly desirable and little, if any, derating will
occur at this level. Some minor burner or combustor modifications will be required and ducting
sizes to the burners must be increased. Combustion gas production however is approximately equiva-
lent to natural gas combustion and furnace sizes can remain relatively equivalent.
This situation changes significantly when the gas heating value drops down to the 150 Btu/scf
range equivalent to an air-blown gasifier's output. Inlet sizes to the burners continue to grow
with the decrease in heating value and flue gas volumes begin to increase such that at 100 Btu/scf
the flue gas volume is up by at least 50 percent. The capabilities for handling this increased
quantity of gas in a furnace may or may not exist. Present data indicates that furnaces designed
for coal, particularly high ash coals, will be capable of handling the increased throughput, but
that furnaces designed for gas and oil firing will not. Derating of the furnace for 100 to 200 Btu/
scf gas of about 5 percent can be expected. Similar results occur in gas turbines where again the
fuels may be burned, but accommodations must be made for the increased gas throughput. Based on
work to date it appears that both in furnaces and gas turbines, clean combustion of synthetic gases
down to 100 Btu/scf is fully feasible with design provisions for the increases in volumetric flows.
Data reported by Martin (Reference 182) for furnaces and Klapatch (Reference 168) and Pillsbury, et
al. (Reference 215) for gas turbines indicates that combustion of low-Btu gas also produces major
reduction in NO emissions without reported increases in smoke or visible particulates. Thus it
can be presumed that clean combustion of low-Btu gas is possible and that any particulate problems
are due to ash carryover from the process.
The approach to particulate carryover is substantially different between Cases 2 and 3 for
two reasons:
• The combined cycle applications for Case 2 impose much more stringent restrictions on
tolerable particulate levels than the NSPS which can be presumed to govern Case 3
• The economics of the combined cycle plant is quite sensitive to the gas inlet tempera-
ture and pressure and thus particulate removal must be performed on a hot gas stream (as
must H2S removal)
4-3
-------
The pertinent limit imposed by the New Source Performance Standard of 0.1 Ib of participate
per million Btu is compared in Figure 4-1 to limits for particulate admission to gas turbines as
specified by the manufacturers and reported by Fulton and Youngblood (Reference 129). The comparable
specification for the Lu'nen combined cycle plant is also indicated on this figure. Obviously the
turbine inlet limits will drive the particulate cleanup in Case 2. For turbine applications the
problem is magnified by the necessity to remove both particulate and H2S at elevated temperature
(-1000 to 2000°F). The approaches to this monumental task are discussed in References 129 and 270,
but no high temperature cleanup device to obtain either the particulate or H2S levels required is
near commercial application.
While it is possible with the Case 3 applications to consider effluent cleaning, this requires
handling much greater gas volumes (which generally size particulate collection devices) and also
adds problems with ash deposition on the heat transfer surface. The only advantage to post-combus-
tion cleanup is that for a retrofit application, this may allow use of existing installations. The
data obtained on the particulate loadings to be expected out of the gasifier is summarized in
Figure 4-1. It is obvious from the paucity of points that data on particulate output is virtually
nonexistent. This is true probably for three reasons:
• Data on particulate is not especially germane to facility operation
• Collection of credible particulate data is difficult and time consuming
• For many processes the particulate is removed in other steps
This latter consideration is particularly pertinent to Lurgi-style fixed and moving bed gasifiers.
The product from these devices is usually loaded with tars, phenols, and other condensible and/or
water-soluble organics. This material, which presents major problems in downstream components, is
classically removed with a wet scrubber which also removes the ash particulates. This is feasible
with these gasifiers since they do not usually admit fines to the reaction zone. The only data
located on the entrainment experienced with these reactors was obtained in U.S. Bureau of Mines
tests of a stirred bed gasifier (Reference 220). The typical coal charged to the gasifier was a
subbituminous A crushed such that 67 percent was greater than 1/4 inch, 13 percent was between 1/4
and 1/16 inch, and 20 percent was less than 1/16 inch. Typical results showed that about 1.7 per-
cent of the coal was entrained in the product gas. Of that 1.7 percent, approximately 96 percent
was removed in a cyclone with the following distribution (Table 4-2). The approximate range of par-
ticulate from the USBM reactor ahead of and downstream of the cyclone are shown in Figure 4-1.
4-4
-------
Ignifluid (Uncontrolled)
Koppers-Totzek (Uncontrolled)
C02 Acceptor —v
(Uncontrolled) JL
Westinghouse Fluid Bed
(Uncontrolled)
USBM Stirred Bed )/>
(Ahead of Cyclone)
Winkler Stirred Bed
Conventional Combustion of
Coal Without Controls'
NEW SOURCE PERFORMANCE STANDARDS
A-12519
USBM Stirred Bed
(Downstream of Cyclone)
Koppers-Totzek-Downstream of Scrubber
6E Gas Turbine Limit — «— —
UA Gas Turbine Limit ————————
Lunen Combined Cycle - 5.10"
3
c
<= £
s-
o
o
-Jo
Figure 4-1. Data on particulate from synthetic gases.
4-5
-------
TABLE 4-2. PARTICULATE SIZE DISTRIBUTION FROM
STIRRED BED REACTOR (Reference 220)
Sieve Sizing
Sieve
Passing
16
30
50
100
200
Sieve
Retaining
16
30
50
100
200
Dimensions
Max Size (y)
1,588
846
508
254
127
Min Size (u)
1,588
846
308
254
127
Fraction
%
0.2
0.2
1.4
9.7
63.0
Cumulative
%
0.2
0.4
1.8
11.5
100.0
-------
The problems are substantially different with fluidized bed gasifiers which form the bulk of
the data on Figure 4-1. Here the coal is pulverized to a size which results in major amounts of
entrainment with the product stream, but the beds are classically operated in a mode which discour-
ages the formation of significant quantities of tars and condensibles. Thus these devices rely on
mechanical collectors to a much greater extent. In fact for a commercial scale operation there is
likely to be a continual carryover of bed material, coal particles, and ash into a cyclone which
will be returned to the bed. Typical results for bed elutriation are shown for four fluidized bed
gasifiers (Ignifluid, C02 Acceptor, Westinghouse, and Winkler). It should be noted that the
Ignifluid combined gasifier-boiler fluidizes much more violently than typical for most fluid bed
reactors. This is also reflected in the courseness of the particulate carryover as shown in Figure
4-2 from Reference 269 compared to nominal value for fly ash from pulverized coal. Very sketchy
PARTICLE
DIAMETER
MICRONS
1000
too
10
IGNIFLUID
FLY ASH
j I
o
m
N
I
I 5 10 20 40 60 80 90 95 99
WEIGHT % SMALLER THAN
Figure 4-2. Comparison of ash size from
Ignifluid and pulverized
coal combustor.
results have also been obtained from the C02 Acceptor process which is less violently fluidized.
The particulate there is indicated to be virtually all less than 250 microns and 75 percent is less
than 40 microns (Reference 119). Based on operational results to date, it appears that mechanical
collectors will be adequate to reduce the ash entrained in product gas from fluidized beds to meet
the NSPS levels. Meeting gas turbine specifications may be expected to involve a second stage of
removal, for example a gravel bed filter.
The entrained bed gasifier can be anticipated to face more severe particulate removal problems
since the coal particle sizes are smaller and the particles are entrained in the gas stream. Since
most of those gasifiers are anticipated to run in a slagging mode, the problem is reduced substantially.
4-7
-------
The result is quite similar to a wet bottom pulverized coal boiler. The only data located concerned
the Koppers-Totzek gasifier which shows predictably heavy particulate loading at the gasifier exit.
These devices normally are operated with at least two stages of high-energy wet scrubbers which
routinely reduce the ash concentration to the ranges of interest for a gas turbine (Figure 4-1).
The overall conclusion from this limited data appears to be that particulate effluent from
gaseous synthetic fuel combustion will be due to ash in the product gas and that other factors
(HS$ removal, turbine blade, erosion) will force cleanup of the ash to levels below those of con-
cern for particulate effluent standards.
4.2 LIQUID FUELS
The situation with liquid fuels is even more indeterminate than with the gaseous synthetics.
There are substantial questions of strategy concerning the utilization of liquid fuels in steam
raising applications since present cost projections indicate severe penalities for use of liquids
as opposed to low-Btu gas. While this is somewhat counterbalanced by the ability to store and ship
the liquid fuels, present planning is oriented to use of liquids from coal as petrochemical feed-
stocks and as feed for refineries for production of gasoline and distillate fuels.
The combustion properties of the synthetic liquid fuels have not been exhaustively investi-
gated. Martin (Reference 182) has surveyed the data that is available and concludes that the prin-
cipal problem likely will be NO because of the high levels of fuel nitrogen. He indicates, and
other data confirms, that some amount of refining will be required to improve the viscosity of the
synthetics. This treatment should allow effective atomization of the fuel and thus eliminate this
source of particulate. The remaining problem is the potential for excessive ash passing through
the filters and appearing in the product as discussed in Section 3.2 As shown for Synthoil on
Figure 4-3, ash levels reported could still cause problems if all this ash does pass untouched
through the combustion process. Also shown in the figure is the only other data located on liquid
fuels which was combustion of COED fuels refined to be equivalent to #4 fuel oil. While the nominal
particulate level reported is higher than NSPS, this may be attributed to furnace conditions since
the particulate from the synthetic fuel is about 25 percent of the particulate from natural #4 oil
burned under identical conditions. This seems to indicate that if burners can be tuned to meet NSPS
with natural #4 oil, there should be little problem in doing the same with synthetic oils.
4.3 SOLID FUELS
The final category of chemically desulfurized fuels from coal that should be considered are
the solid products:
4-8
-------
Same
Furnace <
Conditions
Comparable natural #4 oil
Synthoil - Theoretical
Coal #4 oil
NEW SOURCE PERFORMANCE STANDARD
Range for large-scale material
Oil combustion
y//////,
A-12521
o
o
CO
O
0.
o
O)
4->
10
i.
>a
Q-
o
C5
_J O
C
Figure 4-3. Data on particulate from synthetic liquids.
4-9
-------
t Solvent refined coal
• Chemically cleaned coals
The first category has been extensively studied for stationary source steam-raising applica-
tions and in fact SRC is presently the most advanced synthetic fuel in terms of qualification for
use in steam raising. Testing was done on the combustion of SRC in the early 1960's which indicated
adequate performance. At the present time EPRI is sponsoring initial tests on SRC from the present
pilot plants at the boiler manufacturers. Early results from Backcock and Mil cox have indicated
particulate in the range of 0.3 to 0.7 Ibs of particulate per million Btu. This work however is
quite preliminary and there are strong indications that the furnace was not optimized for SRC since
the particulate is about 75 percent unburned carbon. If it is presumed that this carbon can be re-
moved through alterations to the firing process, then the range of SRC ash measured corresponds well
with the theoretical levels which can be calculated from the predicted ash levels in the SRC as
shown in Figure 4-4. These levels also bound the NSPS criteria of 0.1 Ib per million Btu which in-
dicates that NSPS particulate levels will probably be attainable by a combination of careful filtra-
tion to minimize ash in the SRC and firing alterations to ensure complete carbon burn up. The modi-
fications for SRC firing and associated costs are discussed in some detail in Reference 234. At
the present time EPRI is supporting generation of adequate amounts of SRC for extension of those
tests to larger scale.
Chemically cleaned coals, both from the Meyers and Battelle processes, are not available in
sufficient quantities to allow combustion tests. While both processes reduce the ash content of
the coal somewhat, it is still expected that traditional forms of control devices will be required
downstream of combustion.
4-10
-------
o
o
o
o
Uncontrolled coal
Range of SRC in EPRI
tests (including carbon)
Range of ash values in
EPRI SRC tests
Theoretical ash \\///////,
(0.2* ash) Y y yy
to
r— Q.
A-12520 NEW SOURCE PERFORMANCE STANDARD
Theoretical SRC
(0.1% ash)
o
o
o
o
Figure 4-4. Data on particulate from SRC.
4-11
-------
SECTION 5
ECONOMICS OF COAL DESULFURIZATION
While coal conversion has a variety of attractive features for other applications, e.g.,
replacement of natural gas and imported petroleum, for large steam-raising boilers its primary
role must be considered to be reduction of fuel sulfur content. Fuel desulfurization is merely one
means of meeting the mandated levels of S02 in stationary source effluent. For widespread accep-
tance of fuel cleaning, it must demonstrate that there are substantial economic advantages to re-
moving sulfur prior to combustion as opposed to flue gas scrubbing. This section attempts to per-
form this comparison while considering the effect of particulate removal requirements.
The economics of all coal desulfurization methods are presented shrouded in controversy and
accurate numbers are difficult to obtain. With flue gas desulfurization processes the uncertainty
is largely due to assumptions on the applicability of existing cost data to new installations. Un-
fortunately the uncertainty with fuel cleaning processes is due to a near-total lack of data on the
economics of full-scale operation on U.S. fuels. In fact, the costs which have been used to justify
construction of commercial units, the two Four Corners area high-Btu coal gasification plants, have
increased so rapidly that the future of both plants is extremely cloudy. Estimated costs for
a Four-Corners type of SN6 plant using demonstrated technology throughout with Lurgi gasifiers
have grown from about $350 million to close to $1 billion in the space of about a year (Reference
166). In reviewing the reasons for this, Reference 166 suggests a variety of causes having effects.
• Cost studies for the lower figures were made prior to the major inflationary surge of
the last 2 years
• The scope of the cost estimate may have been more limited in the first studies
• Environmental constraints may have been underestimated initially both in requirements im-
posed and delays caused by need for additional studies
• Possible overly optimistic view of cost trends, times required for permits, etc. when
the plants were first proposed
5-1
-------
Whatever the reasons (undoubtedly they all played a part), this type of fluctuation in cost calls
into question the credibility of all cost estimation on coal conversion processes. Particularly
vulnerable are cost estimates for processes which have not proceeded past the PDU stage if factors
of 3 in cost growth are seen for existing commercial concepts. This degree of uncertainty appears
to be unresolvable until some full-scale units are built and operated commercially.
A recent study by the Tennessee Valley Authority for EPRI (Reference 258) has attempted to
perform the comparison of coal gasification processes with flue gas desulfurization processes.
This is the most recent extensive study of the tradeoffs between the two desulfurization modes. It
addresses in substantial detail the costs associated with six different configurations of fixed-
bed gasifier and gas cleaning system using either the Lurgi pressurized fixed-bed or the Wellman-
Galusha atmospheric fixed-bed gasifiers. The equivalent costs for the flue gas desulfurization
methods were derived from Reference 184 where the TVA analyzed, using the same ground rules, five
FGD concepts. The concepts analyzed are shown below.
TABLE 5-1. PROCESSES SELECTED FOR COMPARISON
Coal Gasification/^S Removal
Wei 1man-Galusha/Stretford
Wellman-Galusha/Iron Oxide
Wellman-Galusha/Iron Oxide/Fines Gasification
Lurgi/Benfield
Lurgi/Stretford
Lurgi/Iron Oxide
Flue Gas Desulfurization
Limestone Slurry
Magnesia Slurry-Regeneration
Lime Slurry
Catalytic Oxidation
Sodium Solution-S02 Reduction
The assumptions utilized in the comparison are shown in Table 5-2 for the technological assum-
ptions and in Table 5-3 for the economic assumptions taken from Reference 258. The results obtained
utilizing the data handled under the above assumptions are presented in Table 5-4 for the capital
costs of the various systems and then these capital costs merged with projected operating costs to
obtain a total annual revenue requirement as shown in Table 5-5. Both tables are taken directly
from Reference 258.
The results obtained by the TVA study indicate fairly conclusively that there will be a sig-
nificant advantage to use of flue gas desulfurization rather than gasification. To examine the po-
tential for savings from elimination of particulate controls downstream of the steam generator
5-2
-------
TABLE 5-2. MAJOR DESIGN ASSUMPTIONS FOR COMPARISON
1. The hot raw gas from the fixed-bed gasifier passes through cyclones, the iron oxide
purification unit, and ducting to the power unit burners without fouling any of
these facilities.
2. Air-blown, fixed-bed gasifiers which have an inside diameter of 12 feet can be
designed to process sized, caking-type coal.
3. The coal gasification rate for the near-atmosphereic systems is 80 lb/(hr)(ft2) of
grate area and, for the elevated-pressure system, it is 350 lb/(hr)(ft2).
4. The typical coal, based on a cross section of those coals used by TVA in 1972, has
the following properties: heat content, 10,800 Btu/lb; ash content, 16.7 percent
by weight; sulfur content, 3.5 percent by weight; ash fusion temperature, 2,300 to
2,500°F; free swelling index, 3 to 7; size, 85 percent 2 inch by 1/8 inch and 15
percent minus 1/8 inch,
5. Coal fines are either gasified in a Koppers-Totzek gasifier or sold as a byproduct.
6. The net heating value of the low-Btu gas (wet basis) leaving the gasifier (excluding
tars) in the near-atmospheric systems is 137 Btu/scf and in the elevated-pressure
systems, 145 Btu/scf.
7. The quantity of the oil and tar produced is 5 percent by weight of the sized coal
feed. The tar and oil mixture is burned in the power unit furnace and has a heating
value of 17,000 Btu/lb. Ammonia and crude phenols are recovered as byproducts from
the tar removal unit.
8, Desulfurization facilities are provided to control sulfur emissions below 1.2 Ib of
S02/million Btu heat input to the system. The desulfurization facilities produce
sulfur as the only byproduct.
9. In the hot iron oxide unit, the capacity of the iron oxide which contains 25 percent
Fe203 is 5 Ib of sulfur/100 Ib of absorbent in the near-atmospheric systems and 8 Ib
of sulfur/100 Ib of absorbent in the elevated-pressure systems. In the hot iron
oxide unit, oxygen is required for regenerating the spent absorbent.
10. Following gas quenching for heavy tar removal, closed-circuit heat exchangers are
used to maximize the heat recovery within the system. The exchangers are designed
to handle any condensing oils without fouling.
11. The gasification system is retrofitted to an existing 500-MW power unit which is
derated by 5 percent to 475-MW when the modified unit is fired with low-Btu gas.
5-3
-------
TABLE 5-3. MAJOR ECONOMIC ASSUMPTIONS FOR COMPARISON PURPOSES
en
1. The coal-fired power unit is 5 years old with a remaining life of 25 years.
2. The 1975 costs of construction materials and labor were developed using projections
of the Chemical Engineering Cost Indices: 174.8 for materials and 184.1 for labor.
The costs for operating labor, raw materials, and utilities were projected to 1975.
3. The initial annual revenue requirements are based on an operating time of 7,000 hr
and are used to project lifetime revenue requirements over a predefined 25 year
declining operating schedule.
4. A regulated utility economic basis (earnings on equity and borrowing capital and
income taxes included) is used. The base value for the annual revenue required
for capital-related items is 15.3 percent of total original capital investment.
Interest on borrowed capital is 8 percent/year, return on equity is 12 percent/
year, and the borrowed-to-equity funding ratio is 1:1.
5. To meet commitments for electricity during the outage of the power unit for the
installation of the gasification system, power equivalent to that which would have
been the output of the power unit is purchased for 10 weeks. The electricity is
sold at its purchased price however, the transmission cost is applied toward the
capital investment of the gasification system.
6. Costs based on Midwest plant location with project beginning mid-1973 and ending
mid-1976. Average cost basis for scaling chosen to be mid-1975 dollars.
-------
TABLE 5-4. TOTAL CAPITAL INVESTMENTS OF COAL GASIFICATION
AND STACK GAS SCRUBBING SYSTEMS FOR RETROFITTING
A 500 MW POWER UNIT
Ul
I
en
System
Flue Gas Desulfurization
Limestone Slurry
Magnesia Slurry-Regeneration
Lime Slurry
Sodium Solution-S02 Reduction
Catalytic Oxidation
Gasification
Wellman-Galusha-Iron Oxide
Wellman-Galusha-Iron Oxide-Fines Gasification
Lurgi-Benfield
Wei Iman-Gal usha-Stretf ord
Lurgi-Stretford
Lurgi-Iron Oxide
Total Capital Investment
106 $
25.6
28.6
28.7
34.4
45.5
161.0
201.8
211.5
221.1
234.8
234.9
$/kW
51
57
57
61
91
339
425
445
465
494
495
-------
TABLE 5-5. TOTAL AVERAGE ANNUAL REVENUE REQUIREMENTS OF
COAL GASIFICATION AND STACK GAS SCRUBBING SYSTEMS
FOR RETROFITTING A 500 MW POWER UNIT
(Including capital costs from Table 5-4)
01
i
O»
System
Flue Gas Desulfurization
Limestone Slurry
Magnesia Slurry-Regeneration
Lime Slurry
Catalytic Oxidation
Sodium Solution-S02 Reduction
Gasification
Wellman-Galusha-Iron Oxide
Wellman-Galusha-Iron Oxide-Fines Gasification
Lurgi-Benfield
Wei Iman-Gal usha-Stretford
Lurgi-Iron Oxide
Lurgi-Stretford
Total Average Annual
Revenue Requirements
106 $
7.9
9.6
9.6
13.3
14.7
38.9
48.3
52.4
52.9
55.4
56.3
Mills/kWh
2.26
2.75
2.75
3.80
4.19
11.71
14.53
15.75
15.91
16.65
16.94
-------
burning low-Btu gas, the costs of dust collection were estimated. The basis of the data was Refer-
ence 201 updated from 1967 to 1975 by use of the CE Cost Index. For a 500 MW plant in 1975, this
predicts an installed cost for an electrostatic precipitator of about $20/kw and an annual cost.of
about 0.1 mil per kilowatt-hr. Unfortunately even with this credit, the gasification plant is still
substantially more expensive than flue gas desulfurization. There unfortunately are no similar
comparative results available for SRC which appears at the present time to be the only other mode
of operation which is likely to be widely used for steam-raising. There is little reason to expect
SRC to be substantially cheaper to manufacture, although its accomodation in a steam plant should
be much simpler.
In order to provide some perspective on the costs associated with power generation by various
methods, a comparison has been done between various modes of providing electricity in 1980. This
comparison is based generally on a study done by Westinghouse for the Commonwealth of Kentucky and
reported in Reference 123. Additional cases for comparison have been added to increase the perspec-
tive. The data for the additional cases generally came from the Westinghouse results although two
additional data points are included from the TVA study. Note that the Westinghouse data all con-
siders commercial operation by 1980 whereas the TVA information is for mid-1975. The cases are
listed below.
Case 1 -Conventional Steam Plant. No controls for SO- are utilized and a heat rate of 9,000
Btu/kw-hr is assumed. This is the baseline case.
Case 2 - Conventional Steam Plant with a Low Cost for S02 Scrubbers. This assumes a $50 per
kilowatt cost for S0« removal which is the low end of the spectrum of present costs for scrubbers
as reported in Reference 258.
Case 3 - Conventional Steam Plant with a High Cost for SOp Scrubbers. This is identical to
Case 2 except that the value for the S02 device is taken as $120 per kilowatt which is used in the
Westinghouse study.
Case 4 — Conventional Steam Plant burning Low Btu Gas. This is the case of greatest interest
to this study. The cost of the gasifier is assumed to be $250/kw which was presented by Westing-
house. A heat rate of 10,000 Btu/kw-hr was assumed.
Case 5 - Combined Cycle Plant burning #2 Oil. This could also be considered to be the lower
bound cost for synthetic liquids ($2.60/106 Btu).
Case 6 - Combined Cycle Plant using Low Btu Gas from the Westinghouse Gasifier. Again a cost
of $250/kw is assumed for the gasification plant.
5-7
-------
Case 7 - Combined Cycle Plant using Low Btu Gas from a Fixed-Bed Gasifier. To illustrate the
uncertainties inherent in these analyses, a nominal cost for fixed-bed gasification in mid-1975 of
$400/kw has been used based on the data shown in Table 5-4.
Base 8 - Gas Turbine operating on #2 Oil. Again this can probably be considered a lower
bound cost for synthetics.
The numerical data used is shown in Table 5-6 which, except as noted for Cases 2 and 7, is
directly from the Westinghouse study. The annualized fixed costs are taken as 18 percent of the
total capital costs. The results are shown in Figure 5-1 as the total annual cost as a fraction of
annual utilization rate. A utilization of rate of 1.0 is assumed to be full-time operation, i.e.,
8,760 hours/year. The results indicate again that all calculations are extremely sensitive to the
assumption made. It does appear that the.relative economy of conventional steam plants using flue
gas desulfurization versus low-Btu gas is quite clear-cut. There is however substantial ambiguity
concerning the economics of combined cycle operation with Low Btu gas. It must be considered that
the Westinghouse estimate is low but the magnitude of this is uncertain until full-scale plant
construction proceeds.
5-8
-------
TABLE 5-6. COMPARISON OF GENERATION METHODS
en
i
10
Case
1
2
3
4
5
6
7
8
Title
Conventional Steam
No Controls
Conventional Steam
Low SOX Costs
Conventional Steam
High SOV Costs
A
Conventional Steam
Gasifier
Combined Cycle
#2 Oil
Combined Cycle
Westinghouse
Gasifier
Combined Cycle
TVA Gasifier
Gas Turbine
#2 Oil
Plant
Heat
Rate
(Btu/kwhr)
9,000
9,400
9,400
10,000
7,300
8,100
8,100
10,500
Power
Plant
430
430
430
430
240
240
240
170
Capital Costs $/kw
S02 Gasifier
-
50
120
-
-
~
-
-
-
-
-
250
-
250
400
-
Total
430
480
550
680
240
490
646
170
Annual
Fixed
Cost
$/kw
77
86
99
122
43
88
116
31
Operating Costs
Mils/kwhr
Fuel 0 & M Total
8.1
8.5
8.5
9.0
19.0
7.3
7.3
27.3
2.5
2.5
2.5
2.5
1.4
3.0
3.0
1.5
10.6
11.0
11.0
11.5
20.4
10.3
10.3
28.8
-------
200
4 5 7
I/)
o
o
te
s_
Ol
a.
o
IO
=1
100
00
CM
0.0
0.4 0.6
Utilization Rate
0.8
1.0
Figure 5-1. Comparison of generation methods.
5-10
-------
REFERENCES
The reference list tabulates the data gathered during the course of this effort. In
addition to the references in text, the material has been cross-referenced by process and
type of information contained. The following tables present the cross-reference lists for
the various categories considered in the examination of particulate from combustion of synthetic
fuels.
R-l
-------
REFERENCES - GASIFICATION PROCESSES
Process
General
Lurgi
Koppers-
Totzek
Ulnkler
Uellman-
Galusha
Ignlfluid
Hygas
C02 Acceptor
Westlnghouse
Bureau of
Mines
Stirred Bed
Gegas
Texaco
Partial
Oxidation
Hydrane
Synthane
Union Carbide
Ash Aglomera-
tlon
Cogas
Fluldlzed Bed
8CR
U-Gas
81 -Gas
C-E Entrained
B&W Entrained
Bed
Foster-Wheeler
Entrained Bed
BYU-En trained
Bed
Kellogg Molten
Salt
Atomics Int'l
Molten Salt
Molten Iron
Other
Process
Description
2, 9, 19. 20, 25,
29. SO. 51. 52.
63. 82. 83. 93,
105. 132. 150,
177, 197. 203,
210. 244. 245.
246. 251. 254,
257
88, 141. 142. 148,
170, 185, 193. 223,
238, 250
57, 58. 113, 114,
115, 165, 181,
192, 262
78, 93
93
245. 246, 26.'
231, 232, 256
100, 110. 119
60. 70, 75, 123,
147. 194
167, 174, 220
53, 171, 205.
264
97. 98
117, 136, 266
61. 122, 255
28. 93, 132
224, 239
251
176
68, 71, 133
138. 208. 209
213
32
251
95
251
172
38, 39. 43. 46,
56, 107, 119,
- 121, 190, 218,
235, 244
Status
19, 30. 35, <10.
42, 51, 62, 63
90. 143. 166.
191, 198. 244,
251, 260, 261.
271
14. 17, 41, 62,
141, 142, 185.
198
113. 262
78
38. 231
119
194
37, 53, 205
117. 266
122, 255
176
133
Combustion
Data
21, 25. 126,
168, 182.
215. 216,
229. 234
170
115, 116
268
123. 194
98
ParflcuTa!?
Data
84
170
115
268
120
75, 123
220
Process1
Economics
20, 25, 50. 51.
62, 63, 140.
166, 197. 198,
234. 258
62, 193, 198,
250
113. 191, 258
78
258
256
123
167
176
7.1
138, 208, 209
95
Other
72, 96, 102, 104,
1G8, 109, 118.
143, 146, 149.
152, 159. 160.
161, 169. 173.
179. 180, 202,
222, 249
238, 250
181
169
61
R-2
-------
Process
Genera I
COED
TOSCOAL
Garrett
Process
Description
15. 25, 86, 91,
268. 271
67, 162, 163.
164. 178. 22S.
239
87
1. 55. 186. 227,
228
Status
34. 86, 268
164
Combustion
Data
182
164
Participate
Data
25
164,
178
Process
Economics
15
67, 162,
163, 164,
225. 240
1
Other
179. 222
REFERENCES - DISSOLUTION PROCESSES
Process
General
Consol — CSF
M-Coal
Syntholl
SRC
Process
Description
15, 25, 54, 55, 65,
86. 91, 103. 206,
263, 268, 271
48, 64, 73, 131,
204, 214
31, 33, 158, 248
3, 4. 7, 65, 267
27. 36, 60, 89, 106,
151. 207. 236, 237
Status
34, 54. 55. 86.
268
48
11, 31, 89, 106,
207
Combustion
Data
182
127, 183,
196. 226,
234
Partlculate
Data
25
214
207
Process
Economics
15, 65
64. 131,
214
158,. 248
60, 125,
156, 157,
234
Other
179. 222
73
REFERENCES - CHEMICAL COAL CLEANING
Process
General
Meyers
Process
Battell e
Hydrothermal
Process
Description
12. 15, 246, 252,
259
18, 139. 189
59, 101, 247,
265
Status
139
101, 247, 265
Combustion
Data
12
Partlculate
Data
Process
Economics
139
247, 265
j
Other
15. 146
REFERENCES - OTHER TYPES OF DATA
Process
Partlculate
Control
S02 Control
Process
Description
49. 66. 84. 112.
129
44. 81. 84. 129.
184. 241
Status
129
129
Combustion
Data
Partlculate
Data
Process
Economics
66. 49.
112, 201.
81. 184.
241
Other
R-3
-------
Process
Genera I
COED
TOSCOAL
Garrett
Process
Description
15. 25, 86, 91.
268. 271
67, 162, 163.
164. 178, 225.
239
87
1, 55. 186. 227,
228
Status
34, 86, 268
164
Combustion
Data
182
164
Partlculate
Data
25
164,
178
Process
Economics
15
67. 162.
163. 164.
225, 240
1
Other
179, 222
.
REFERENCES - DISSOLUTION PROCESSES
Process
General
Consol — CSF
M-Coal
Syntholl
SRC
Process
Description
15, 25, 54, 55, 65.
86, 91, 103, 206,
263, 268, 271
48, 64, 73, 131,
204, 214
31, 33, 158, 248
3, 4, 7, 65, 267
27, 36, 60, 89, 106,
151. 207, 236, 237
Status
34, 54. 55. 86,
268
48
11, 31, 89, 106,
207
Combustion •
Data
182
127, 183,
196, 226,
234
Particulate
Data
25
214
207
Process
Economics
15, 65
64, 131,
214
158, 248
60, 125,
156, 157,
234
Other
179, 222
73
t
REFERENCES - CHEMICAL COAL CLEANING
Process
General
Meyers
Process
Battelle
Hydrothermal
Process
Description
12, 15, 246, 252,
259
18, 139, 189
59, 101, 247.
265
Status
139
101, 247, 265
Combustion
Data
12
Partlculate
Data
Process
Economics
139
247, 265
i
Other
15, 146
REFERENCES - OTHER TYPES OF DATA
Process
Partlculate
Control
S02 Control
Process
Description
49, 66, 84, 112,
129
44, 81, 84, 129,
184, 241
Status
129
129
Combustion
Data
Particulate
Data
Process
Economics
66, 49,
112, 201,
81, 184,
241
Other
R-3
-------
LITERATURE SURVEY - PARTICULATE GENERATION FROM COMBUSTION OF COAL-DERIVED FUELS
1 >. ADAM, D, £., ET AL 'COAL PROCESSING! COAL GASIFICATON BY PYROLYSIS',
CHEMICAL ENGINEERING PROGRESS, JUNE 1974, PP, 74-75
2 * AHNER, D.J. AND BOOTHE, W,A,, 'PROCESS SYSTEMS FOR CONVERSION OF DIFFI-
CULT FUELS TO SYNTHETIC FUELS FOR BASELOAD GAS TURBINES', ASME 75-GT-73,
DECEMBER 2, 1974
3 * AKHTAR, S., ET AL, 'LOW-SULFuR LIQUID FUELS FROM COAL,' ENERGY SOURCES,
1974,
4
-------
13 * ANON, 'TWO CLEAN-COAL PROJECTS REACH PILOT-PUN? STAGE,' COAL AGE, DEC
I97a.
14 * ANON, 'SOUTH AFRICA POUR3 ON THE COAL,' CHEMICAL WEEK. JAN 1975.
15 * ANON, (LIQUEFACTION AND CHEMICAL REFINING OF COAL,1 BATTELLE ENERGY
PROGRAM, COLUMBUS, OHIO, JULY* 1974
16 * ANON, (SOUTH AFRICA DETAILS ITS SECOND SASOL PROJECT,' COAL AGE, FEB
l«75.
17 * ANON, »FPC APPROVES SLOWDOWN OF COAL GAS PLANT,(WEEKLY ENERGY REPORT,
APRIL 28, 1975
18 * ANQN, OTEAM, 38TH EDITION*, 3ABCOCK AND WlLCOX, NEW YORK,1972
19 * ANON,, 'COAL TECHNOLOGY! KEY TO CLEAN ENERGY,' OCR ANNUAL REPORT, 1971*
1974.
30 * ANON,, 'EVALUATION OF COAL-GA3IFICATION TECHNOLOGY,PART 1, PIPELINE
QUALITY GAS,' OCR R+D REPORT 74, INTERIM REPORT NO, i.
21 * ANON., 'CONSIDER BURNING LOW.BTU GASEOUS FUEL AND HEAVY OIL IN GAS
TURBINES,' POWER, JUNE 1974.
22 * ANON,, 'COAL GASIFICATION PILOT PLANT SCORES MILESTONE ACHIEVEMENT*,
ERDA NEWS RELEASE, MAY 29, 1975
IS * ANON,, 'U.S. COAL-TO-GAS PROCESS IS READY,' THE OIL AND GAS JOURNAL,
SEPT, 9, 1974, PP.86-88,
24 * ANON,, (ENERGY R AND D • AN OVERVIEW,' RESEARCH/DEVELOPMENT, SEPT,
1974, PP, 50-54,
IS * ANON,, 'SYMPOSIUM PROCEEDINGS, ENVIRONMENTAL ASPECTS OF FUEL CONVERSION
TECHNOLOGY,1 EPA.650/2-74-118,OCT.,1974
26 * ANON,, »THE FUELS OUTLOOK', ELECTRICAL WORLD, JUNE 15, 1975
R-5
-------
27 * ANON,, (CLEANING COAL BY SOLVENT REFINING!, ENVIRONMENTAL SCIENCE *
TECHNOLOGY, VQL» 6, NO, 6, JUNE 1974
28 * ANON,, (CHEMICALS FROM COALl BEST BET IN ENERGY CRISIS?*, CHEMICAL MEEK
JUNE 12, 1970
29 * ANON,, (U.S. URGED TO STRESS HlGH-BTU GASIFICATION', THE OIL AND GAS
JOURNAL, MARCH 17, 1975
SO * ANON,, 'GAS FIRM RESUMES PLAN FOR GASIFICATION UNIT', COAL AGE
31 * ANON,, (COAL CONVERSION PROJECTS ADVANCE!, COAL AGE, JANUARY 1975
32 * ANON,, (COMBINED CYCLE PLANT TO BE BUILT BY FOSTER-WHEELER,•
CHEMICAL ENGINEERING PROGRESS, APRIL, 1975
33 * ANON,, (FIRST PHASE CONTRACT FOR COAL LIQUEFACTION PLANT LET,1
CHEMICAL ENGINEERING PROGRESS, APRIL, 1975
34 * ANON., 'U.S. COAL-LIQUEFACTION USE SEEN 4-10 YEARS AWAY*, THE OIL AND
GAS JOURNAL, SEPTEMBER 16, 1974
35 * ANON,, "MERCER COUNTY COAL GASIFICATION PLANT DELAYED ANOTHER YEAR',
ENERGY DIGEST, FEBRUARY 17, 1975
36 * ANON., (SOLVENT REFINED COALl A PROCESS TO PROVIDE A CLEAN, HIGH-ENERGY
FUEL COMPATIBLE WITH ENVIRONMENTAL CONCERNS!, THE PlTTSBURG * MIDWAY COAL
MINING CO.
37 * ANON,, (EPRI GRANTS COAL-GASIFICATION PROJECT TO GE', ELECTRICAL WORLD,
JUNE 15, 1975
36 * ANON,, ICOAL-GAS PLANT SAVES FUEL COSTS', THE OIL AND GAS JOURNAL*
AUGUST 4, 1975
39 * ANON,, 'TEXAS UTILITIES BUY SOVIET GASIFICATION PROCESS*, ENERGY DIGEST
MARCH 24, 1975
40 * ANON., (EMPHASIZING THE CRITICAL IMPORTANCE OF AN EXPANDED R+D PROG-
RAMME FOR COAL'S FUTURE*, SECOND INTERNATIONAL COAL RESEARCH CONFERENCE,
JANUARY 1975
R-6
-------
«1 * ANON.i 'US-BRITISH GASlFlER PROJECT SUCCESSFUL', ELECTRICAL WORLD*
JULY it 1975
42 * ANON,, "SUMMARY OF ANNOUNCED PLANS FOR COAL CONVERSION PLANTS'* COAL
ACE* MARCH 1975
43 * ANON.* 'IN SITU GASIFICATION STUDIED IN TEXAS', COAL AGE* JANUARY 1975
44 * ANON,* »HOW MULTIPLE TECHNOLOGIES APPROACH COAL DESULFURIZATION PROBLEM
COAL AG£» JUNE 1975
45 * ANON,* I AIR POLLUTION FROM FyEL COMBUSTION IN STATIONARY SOURCES'*
NTIS, PB«222 341, OCTOBER 1972
46 * ANON,* 'COAL SUPPLY/DEMAND PATTERNS IN THE UNITED STATES', WEEKLY COAL
STATUS REPORT NO, 3, NOVEMBER 1974
47 * ANON,* 'ANALYSES OF TIPPLE AND DELIVERED SAMPLES OF COAL'* BUREAU OF
MINE! REPORT OF INVESTIGATIONS/I^
4B * ANQN,* 'FINAL REPORT. DEVELOPMENT OF CSF COAL LIQUEFACTION PROCESS',OCR
R*D RtPQ*T NO, 39 - VOL, V
«9 * ANON.* 'CONTROL TECHNI8UE3 FOR PARTICULATE AIR POLLUTANTS', EPA AP-51,
JANUARY 19fc9
80 * ANON,* (OPTIMIZATION OF COAL GASIFICATION PROCESSES'* OCR RtD REPORT
NO, 66, INTERIM REPORT NO. 1* VOLUMES 1*2
31 * ANON,* 'PROJECT INDEPENDENCE, A CRITICAL LOOK'* CHEMICAL ENGINEERING,
JAN. 6* 1975* PP 92-105
52 * ANON,, 'POWER GENERATION-CLEAN FUELSVTODAY,' ELECTRIC POWER RESEARCH
INSTITUTE, EPRI*8R*1, APRIL* 1974,
53 ft ANON,* 'GE GIVES DETAILS OF LOH-BTU GAS PROCESS', C+EN, JULY 7, 1975
5« ft ANON,, ICOALCON HOLDS CONTRACT FOR 1237 MILLION DEMONSTRATION PLANT*,
CHEMICAL ENGINEERING PROGRESS, APRIL 1975
R-7
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55 * ANON,, 'PROCESSES CONVERT COAL* WASTES TO LIQUID FUEL'. C+EN, APRIL 1«,
1975, PP. 17-18
56 * ANON,, 'PROSPECTS IMPROVE FOR GASIFYING COAL IN SITUt, C+EN, APRIL 10,
1975 PP. 18-19
57 * ANON,, 'THE NEED FOR ENERGY . AND THE ROLE OF THE KOPPERS-TOTZEK COAL
GASIFICATION PROCESS', KOPPERS CO., INC«, PITT3UBRGH, PA.
50 * ANON,, 'COAL GASIFICATION! THE KOPPERS-TOTZEK PROCESS*, KOPPERS, CO.,
INC., PITTSBURGH, PA,
59 * ANON,, 'CLEANING UP COALS A NEN ENTRY IN THE ENERGY SWEEPSTAKES',
SCIENCE* VOL, 189, JULY 11, 1975
60 * ANON,, 'DEVELOPMENT OF A PROCESS FOR PRODUCING AN ASHLESS, LOW-
SULFUR FUEL FROM COAL, VOL. I, PART «,» R+D REPORT NO. 53.- INTERIM
REPORT NO, 5, NOV 73,
6i * ANON,, ISYNTHANE COAL GASIFICATION PILOT PLANT TO DEMONSTRATE FEASIBIL-
ITY OF CONVERTING COAL TO SUBSTITUTE NATURAL GAS', FINAL ENVIRONMENTAL
STATEMENT, DEPT. OF THE INTERIOR.
62 * ANON,, 'SCRUBBERS VS GASIFIERS,' THE MET SCRUBBER NEWSLETTER,
MARCH 1975,
63 * ANON,, 'PROJECT INDEPENDENCE! TASK FORCE REPORTwSYNTHETIC FUELS FROM
COAL*' U.S. DEPT. OF INTERIOR, NQV, 197«
64 * ANON,, (ENGINEERING EVALUATION AND REVIEW OF CONSOL SYNTHETIC FUEL
PROCESS,' R+D REPORT NO. 70, FEB. 72
69 * ANON*, 'DEMONSTRATION PLANT-CLEAN BOILER FUELS FROM COAL-PRELIMINARY
DESIGN/CAPITAL COST ESTIMATE,' R+D REPORT NO. SB-INTERIM REPORT NO. 1.
66 * ANON,, 'APPLYING AIR POLLUTION CONTROL EQUIPMENT,' REPRINTS FROM
POLLUTION ENGINEERING MAGAZINE
67 * ANON., 'PRODUCTION OF ELECTRICITY VIA COAL AND COAL-CHAR GA8IFICA
TION,' R+D REPORT NO. 66 - INTERIM REPORT NO. 3, JUNE 73.
66 * ANON,, 'GAS GENERATOR RESEARCH AND DEVELOPMENT PHASE II. PROCESS AND
EQUIPMENT DEVELOPMENT,' R*D REPORT NO. 20 FINAL REPORT. MAR 65- SEPT 70.
R-8
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69 * ANON., 'CLEAN POWER GENERATION FHOM COAL*' R*D REPORT NO. 8«,
JUNE 72 • JAN 73.
TO * ANON,, 'ADVANCED COAL GASIFICATION SYSTEM FOR ELECTRIC POWER GENERA-
TION,! P+O REPORT NO. 81 - INTERIM REPORT NO, li AUG 72 • JUNE 73.
7i * ANON,, 'ENGINEERING STUDY AND TECHNICAL EVALUATION OF THE BITUMINOUS
COAL RESEARCH, INC, TWO-STAGE SUpER PRESSURE GASIFICATION PROCESS,' R+D
REPORT NO, 60, 1971
72 * ANON,, 'FEASIBILITY STUDY OF A COAL SLURRY FEEDING SYSTEM FOR HIGH
PRESSURE GASIFIERS,' R+D REPORT NO, 68 FINAL REPORT, JUNE -DEC i97t
73 * ANON,, 'ENGINEERING EVALUATION OF PROJECT GASOLINE CONSOL SYNTHETIC
FUEL PROCESS,' R+D REPORT NO, 59, 1970
7U * ANON., 'CONTROL TECHNIQUES FOR SULFUR OXIDE AIR POLLUTANTS,*' NAPCA
PUBLICATION AP-52, JAN, 1969,
75 * ARCHER, D.H., ET AL, 'COAL GASIFICATION FOR CLEAN POWER PRODUCTION,'
CLEAN FUELS FROM COAL, SEPT 1973,
76 * AUNTER, THOMAS W,, (BITUMINOUS COAL AND LIGNITE', BUREAU OF MINES
BULLETIN 650, PP. 35-61
77 * BAILEY, RALPH £,, 'COAL AS .A KEY TO U.S. ENERGY POLICIES', SECOND
ANNUAL SYMPOSIUM COAL GASIFICATION, LIQUEFACTION, AND UTILIZATION,
AUGUST 5»7, 1975
7S * BANCHIK, I.N,, 'THE WINKLER PROCESS FOR THE PRODUCTION OF LOW-BTU GAS
FROM COAL,1 CLEAN FUELS FROM COAL. SEPT 1973.
79 * BARTOK, W,, ET *L, 'SYSTEMATIC FIELD STUDY OF NQX EMISSION CONTROL
METHODS FOR UTILITY BOILERS,' EPA CONTRACT NO, 70-90, DEC. 1971.
BO * BARTOK, N(, ET AL, 'FIELD TESTINGl APPLICATION OF COMBUSTION MODIFICA-
TIONS TO CONTROL NOX EMISSIONS FROM UTILITY BOILERS,' EPA CONTRACT NO. 68-
02-0227, JUNE 1974,
•i * BECKER, DAVID F,, 'ASSESSMENT OF 302 CONTROL ALTERNATIVES AND IMPLEMEN-
TATION PATTERNS FOR THE ELECTRIC UTILITY INDUSTRY', 66TH ANNUAL MEETING OF
THE AIR POLLUTION CONTROL ASSOCIATION, JUNE 2«-2B, 1973
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82 * BODLE,W,W,, AND K.C. VYAS, ICLEAN FUELS FROM COAL,' OIL AND GAS
JOURNAL, AuG, 26, 197«, PP 73-88.
83 * BOYD,N,F., »COAL CONVERSION PROCESSES LOOM BIG AS A SOURCE OF HYDROCAR
BON FUELS,! MINING ENGINEERING! SEP.
8fl * 8QZZUTO* C.R., £T AL» 'AIR POLLUTION ASPECTS OF ALTERNATIVE ENERGY
SOURCES! * 68TH ANNUAL MEETING OF THE AIR POLLUTION CONTROL ASSOCIATION,
JUNE 15-20, 1975
85 * BROWN, W.C.* 'PETROCHEMICALS A*D OUR ENERGY POLICIES,* CHEMICAL ENG-
INEERING PROGRESS, APRIL 19721 PP. 33*36.
86 * BURKE, O.P.i 'THEY'RE MAKING A SOLID EFFORT TO GET CLEAN COAL LIQUIDS*'
CHEMICAL MEEK, SEPT 11* 1974.
87 * CARLSON, F.B., ET AL» 'THE TQSCOAL PROCESS-COAL LIQUEFACTION AND CHAR
PRODUCTION,' CLEAN FUELS FROM COAL* SEPT 1973,
86 * CHAN, F.K.,
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96 * COX, J.L.r 'CATALYSTS FO* COAL CONVERSION'. CLEAN FUELS FROM COAL, SEPT
1973
97 * CROUCH, W.B., ET AL, "PARTIAL COMBUSTION OF MICH-SULFUR FUELS FOR
ELECTRIC-POWER GENERATION,' IN EPRI-SR-I, APRIL*
98 * CROUCH, W.B., ET AL, 'RECENT EXPERIMENTAL RESULTS ON GASIFICATION AND
COMBUSTION OF LOW BTU GAS FOR GAS TURBINES,' ASME PAPER 74-GT-ll,
99 * CUFFE, 3, T., ET AL, 'EMISSIONS FROM COAL-FIRED POWER PLANTS', NTIS,
PB 174 708, 1967
100 * CUHRAN,G.Pf, ET AL, 'LOW-SULFUR PRODUCER GAS VIA A HIGH TEMPERATURE
REMOVAL PROCESS,' AICHE SYMPOSIUM SERIES, NO, 141, VOL. 70, PP. lOa-115,'
101 * DAWSON, F. G., AND CONNER, J. G., 'BATTELLE ENERGY PROGRAM OVERVIEWS
UNIV. OF PGH. SYMPOSIUM ON COAL GASIFICATION, LIQUEFACTION, AND UTILIZATION
AUG. 1975
102 * DECKMANN, R. W,, 'PETROCHEMICALS FROM COAL', SECOND ANNUAL SYMPOSIUM ON
COAL GASIFICATION, LIQUEFACTION, AND UTILIZATION, UNIV. OF PGH., AUG. 1975
103 * DEL BEL, £., CT AL,'THE LIQUEFACTION OF LIGNITE BY THE C08TEAM PROCESS*
AICHE NATIONAL MEETING, MARCH, 1975
1041 * DEMETER, J.J., ET AL* 'FURTHER STUDIES OF THE COMBUSTION OF PULVERIZED
CHAR AND LOW-VOLATIVE COAL', ASME 73-WA/FU-2, JULY 26, 1973
105 * DENT, P. J. 'THE MELCHETT LECTURE FOR 1965 - EXPERIENCES IN GASIFICA-
TION RESEARCH', JOURNAL OF THE INSTITUTE OF FUEL, MAY 1966
106 * DEPPE,W.L.» 'CLEAN SOLID FUEL CAN BE REFINED FROM COAL,* ELECTRICAL
WORLD, FEB. 1, 1975, PP. 36.39,
107 * DUEL, M,, ET AL, ' DEGASIFICAjION OF COALBEDSl A COMMERCIAL SOURCE OF
PIPELINE GAS', CLEAN FUELS FROM COAL, SEPT. 1973
toe * CASTLAND, D. H,, 'FUEL AND ENERGY USES OF METHANOL*, SECOND ANNUAL SYM-
POSIUM ON COAL GASIFICATION AND LlQUEFICATION, AUG, 1975
109 * ECKARD* WILLIAM E., 'COAL'S INCREASING ROLE IN THE FOSSIL FUEL INDUSTR-
RY», SOCIETY OF PETROLEUM ENGINEERS OF AIME,SPE 5093,OCT, 197a
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no * ELLINGTON, E.E,, ET.AL,, 'PHASE; m AND PHASE IV-A , DESIGN AND CON-
STRUCTION QF THE CONSOLIDATION SYNTHETIC GAS PILOT PLANT, RAPID CITY.
SOUTH DAKOTA,' MARCH 66 • JAN, 72
in * ELLIOTT/ M.A., 'THE GAS INDUSTRY'S LONG RANGE RESEARCH AND DEVELOPMENT
PROGRAM FOR PRODUCING SYNTHETIC FUEL GASES,' ASHE PAPER 74«PET«30, SEPT.
1974.
112 * ENGLUND* H. M,, AND BEERY, w. T,, EDITORS, 'CONTROL TECHNOLOGY! PAR-
TICULATES', APCA, JULY 1973
113 * FARNSMHOTH, J.F., ET AL, 'PRODUCTION OF GAS FROM COAL BY THE HOPPERS*
TOTZEK PROCESS,' CLEAN FUELS FROM COAL, SEPT 1973,
114 * FARNSWQTH, J, F(, ET AL, 'K-Tl KOPPER8 COMMERCIALLY PROVEN COAL AND
MULTIPLE-FUEL GASIFIERI, ASSOCIATION OF IRON AND STEEL ENGINEERS, 1974
ANNUAL CONVENTION, APRIL 1974
us * FARNSWQRTH, j. F,, ET AL, 'CLEAN ENVIRONMENT WITH K-T PROCESS*, EPA
MEETING, MAY 1974
116 * FARNSWQRTH, j, F,, 'UTILITY GAS BY THE K»T PROCESS', EPRI, APRIL 1974
117 * FELDMANr H« f" AND YAi/ORSKY, P. M,, 'THE HYDRANE PROCESS', 5TH AGA/OCR
SYNTHETIC PIPELINE GAS SYMPOSIUM, OCTOBER 1973
118 * FERRETTI* EMMETT J(, 'FEEDING COAL TO PRESSURIZED SYSTEMS', CHEMICAL
ENGINEERING, DECEMBER 9, 1974
119 * FINK, C.E,, 'THE C02 ACCEPTOR PROCESS,' CLEAN FUELS FROM COAL, SEPT
1973,
120 * FINK* CARL, CONOCO COAL CO,, PERSONAL COMMUNICATION, APRIL, 1975
121 * FISCHER, D. D.r AND SCHRIDER, L. A,, (COMPARISON OF RESULTS FROM UNDER*
GROUND COAL GASIFICATION AND FROM A STIRRED BED PRODUCER', AICHE MEETING,
MARCH 1975
122 * FORNEY, J.J., ET AL, 'THE SYNTHANE COAL-TOGAS PROCESS,' CLEAN FUELS
FROM COAL, SEPT 1973,
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423 * FQSTER.PEGG, R. W., ET AL» 'ELECTRIC POWER FROM LOK-BTU 6*3 IN COMBINED
CYCLE POWER PALNTS', SECOND ANNUAL SYMPOSIUM ON COAL GASIFICATION, LIQUE-
FACTION, AND UTILIZATION, UNIV. QF PITTSBURGH, AUG. 5-7, 1975
124 * FRANK, M(E.« + B,K. SCHMID, 'ECONOMIC EVALUATION AND PROCESS DESI6N OF
A COAL-OIL-GAS (COG) REFINERY,' PRESENTED AT THE 65TH AICHE MEETING, NOV
1*72.
125 * FRANK, M, E., AND SCHMID, B, K,, 'ECONOMIC EVALUATION AND PROCESS
DESIGN OF A COAL-OIL-GAS (COG) REFINERY1 CLEAN FUELS FROM COAL, SEPT. 1973
126 * FRENDBERG, A,, 'PERFORMANCE CHARACTERISTICS OF EXISTING UTILITY
BOILERS WHEN FIRED WITH LOW BTU GAS,1 IN EPRI-SR-1, APRIL, i97«.
127 * FREY, DiJi, 'DE-ASHED COAL COMBUSTION STUDY,' CONTRACT NO. 14-01-0001-
417, OCT 1964,
128 * FRIEDMAN, S,, ET AL, 'THE LIQUEFACTION OF LIGNITE BY THE COSTEAM
PROCESS', AICHE MEETING, MARCH 1975
129 * FULTON,R.W. ANP S, YOUNGBLOODf 'SURVEY OF HIGH-TEMPERATURE CLEAN-UP
TECHNOLOGY FOR LOH BTU FUEL GAS PROCESSES,' AERQTHERM REPORT 79-134, JAN.
im.
iso * GAMBS,G.C., AND A.R, RAUTH, ITHE ENERGY CRISIS,* CHEMICAL ENGINEER-
ING, MAY 31, 1971, PP. 56-68.
131 * GILLILAND, EDWIN R,, ET ALi, 'FINAL REPORT OF THE ADVISORY COMMITTEE
ON PROJECT GASOLINE NATIONAL ACADEMY OF ENGINEERING,' R*D REPORT NO. 62,
JAN 70 • OCT 70.
132 * GOODRIDCE,E.R., 'AMERICAN GASIFICATION PROCESSES INCH CLOSER TO
SUCCESS,' COAL AGE, DEC. I97«, PP, 60-65.
133 * GRACE, R.J., 'DEVELOPMENT OF THE BI-GAS PROCESS,i CLEAN FUELS FROM COAL
, SEPT 1973.
isa * GRAHAM, j., ITHE NEW COAL AGEI UTILITY NEEDS WILL BRING UNPRECEDENTED
DEMAND', ELECTRICAL WORLD, JUNE i, 1975
135 * GRAINGER, Lt, 'THE ROSENS COAL SCIENCE LECTURE 19741 COAL INTO THE
TWENTY-FIRST CENTURY', JOURNAL OF THE INSTITUTE OF FUEL, JUNE 1975
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136 * CRAY* j. A,, ET AL» 'PRODUCTION OF HIGH-BTU QAS BY THE HYDRANE PROCESS*
U, S. BUREAU OF MINESi DEPT. OF THE INTERIOR,
137 * GUNNES8,R.C.» 'THE ENERGY CRISIS! REAL OR IMAGINARY?** CHEMICAL ENG-
INEERING PROGRESS, APRIL 1972, PP, 26*32,
138 * HAHN, R, L,, AND PATTERSON, R, CM 'LOW-BTU GASIFICATION OF COAL. PHASE
II AN EVALUATION FOR ELECTRIC POWER GENERATION'* 1EEE-A3ME-A8CE JOINT POWER
GENERATION CONFERENCE, 3E.PT. 1974
139 * MAMER3MA,J,W,, ET ALf 'CHEMICAL DE3ULFURIZATION OF COALl REPORT OF
BENCH-SCALE DEVELOPMENTS, VOL, i*» EPA-R2-73-173A* FEB. 1973,
140 * HAHHON, 0, AND ZIMHERMA, H, B«* 'THE ECONOMICS OF COAL-BASED SYN-
THETIC GAS»» TECHNOLOGY REVIEW, JULY/AUGUST 1975
141 * HATTEN,J.L., »PL*NT TO GET PIPELINE-QUALITY GAS FROM COAL*' THE OIL
AND 6AS JOURNAL, JAN, 20, 1975, PP. 72-76.
142 * HATTEN, J, L., (PIPELINE QUALITY GAS FROM COAL', MECANICAL ENGINEERING,
JULY, 1975
143 A HAUS6ERGER, A, L., 'HETHANATION OF SYNTHESIS GAS', THE OIL AND GAS
JOURNAL,MARCH 31, 1975
140 * HEGARTY, W,P,, + B,E, MOODY, 'COAL GASIFICATION! EVALUATING THE SI-GAS
SNG PROCESS*' CHEMICAL ENGINEERING PROGRESS, MARCH 1973.
145 * HENRY, J. M,, ET AL, 'PRESSURIZED LON-BTU GAS PRODUCER*, SECOND ANNUAL
SYMPOSIUM ON COAL GASIFICATION, LIQUEFACTION, AND UTILIZATION* BEST PROS-
PECTS FOR COMMERCIALIZATION, UNIV, OF PCH., AUG. 1975
146 « HOFFMAN* L., ET AL* 'AN INTERPRETATIVE COMPILATION OF EPA STUDIES RE-
LATED TO COAL QUALITY AND CLEANABlLITY'* EPA-650/2-74-030* MAV 1974
}47 * HOLMGREN* J.D, AND SALVADOR* L,A,* 'LOH BTU GAS FROM A HE3TINGHOUSE
FLUI9IZED BED SYSTEM*' AICHE PAPER* DECEMBER 1974
140 * H006ENDOORN* J.C./ 'GAS FROM COAL NITH LURGI GASIFICATION AT SASOL*»
CLEAN FUELS FROM COAL* SEPT 1973,
149 * HOOGENDOORN* J,Ci* 'EXPERIENCE WITH FI8CHER-TROPSCH SYNTHESIS AT
IASOLV CLEAN FUELS FROM COAL* SEPT 1973,
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150 * HUEBLER* j,, IGT, 'COAL TO CLEAN FUELS CQNVERSIONSI A PERSPECTIVE'*
67TH ANNUAL MEETING OF TH£ AMERICAN INSTITUTE OF CHEMICAL ENGINEERS, DEC.
1*74
15i * HUFFMAN* EVERETT L* 'SOLVENT REFINED COALS COMBUSTION, MAY 1975
152 * JANKA, J.C. AND MALHOTRA, R., 'ESTIMATION OF CUAL AND GAS PROPERTIES
FOR GASIFICATION DESIGN CALCULATIONS,I R + D REPORT NQ. 22 - INTERIM
REPORT NO, 7, JANUARY 1971,
153 * JANUS* J. B, AND SHIRLEY* B, S., 'ANALYSES OF TIPPLE AND DELIVERED SAM*
PUES OF COAL'* BUREAU OF MINES REPORT OF INVESTIGATIONS NO, 78U6* 1973
15« * JANUS* J.B., (ANALYSES OF TIpPLE AND DELIVERED SAMPLES OF COAL'. BUREAU
OF MINES REPORT OF INVESTIGATIONS 7997, 1975
155 * JANUS* J.B. AND SHIRLEY, B.S., 'ANALYSES OF TIPPLE AND DELIVERED SAMP*
LES OF COAL'* BUREAU OF MINES REPORT OF INVESTIGATIONS 7712* 1973
156 * JIMESON, R,M,, + R.G, SHAVER, 'CREDITS APPLICABLE TO SOLVENT REFINED
COAL FOR POLLUTION CONTROL EVALUATIONS,' PRESENTED AT THE 3RD JOINT MEETING
OF THE AlCHE AND THE INSTITUTO MEXICANO DE INGENIEROS QUIMIC08, SEPT 1970.
157 * JIMESON* R.M.* t J,Mt GROUT* •SOLVENT-REFINED COALl ITS MERITS AND
MARKET POTENTIAL*' SOCIETY OF MINING ENGINEERS TRANSACTIONS* SEPT 1971.
156 * JOHNSON* C.A., ET AL* 'PRESENT STATUS OF THE H-COAL PROCESS*' CLEAN
FUELS FROM COAL* SEPT 1973,
159 * JOHNSON* JAMES L.» 'RELATIONSHIP BETWEEN THE GASIFICATION REACTIVITIES
OF COAL CHAR AND THE PHYSICAL AND CHEMCIAL PROPERTIES OF COAL & COAL CHAR'
AMERICAN CHEMICAL SOCIETY DIVISION OF FUEL CHEMISTRY COAL GASIFICATION SYM-
POSIUM, AUGUST 24-29, 1975
160 * JOHNSON, JAMES L,, 'GASIFICATION OF MONTANA LIGNITE IN HYDROGEN AND IN
HELIUM DURING INITIAL REACTION STAGES', AMERICAN CHEMICAL SOCIETY DIVISION
OF FUEL CHEMISTRY SYMPOSIUM ON STRUCTURE AND REACTIVITY OF COAL AND CHAR,
AUGUST 2«-29, 1975
161 * JOHNSON* J.L.* 'KINETICS OF BITUMINOUS COAL CHAR GASIFICATION WITH
GASES CONTAINING STEAM AND HYDROGENS AMERICAN CHEMICAL SOCIETY DIVISION OF
FUEL CHEMISTRY COAL GASIFICATION SYMPOSIUM, APRIL 8-13* 1973
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162 * JONES, J.F., 11 AL., 'CHAR Oil ENERGY DEVELOPMENT,' R+D REPORT NO.
56 ..INTERIM REPORT NO. i, SEPT 66 * FEB 70.
163 * JONES> JOHN F, ET AL., 'CHAR OIL ENERGY DEVELOPMENT,' R+D REPORT
NO, 75 • INTERS REPORT NO.I, JULY 71 • JUNE 72,
16tt * JONES, J.F., 'PROJECT COED (CHAR»OIL-ENERGY DEVELOPMENT,' CLEAN FUEL3
FROM COAL, SEPT 1973.
us * KAMODY, j. F,, AND FARNSWORTH, J. F,, «GAS FROM THE KOPPERS-TOTIEK
PROCESS FOR STEAM AND POWER GENERATION!, INDUSTRIAL FUEL CONFERENCE, OCT.
197«
166 * KA3PER, STANLEY, 'A STRATEGY FOR COAL GASIFICATION!. SECOND ANNUAL
SYMPOSIUM COAL GASIFICATION, LIQUEFACTION, AND UTILIZATION, AUGUST 5«7,197S
167 « KATELL,S. ET AL. 'THE ECONOMICS OF PRODUCER GAS AT ATMOSPHERIC AND
ELEVATED PRESSURES', BUREAU-OF MiNgS, U.S. DEPT. OF THE I
CATION SYSTEMS FOR RETROFITTING pO«ER PLANTS', EPRI 203-1, INTERIM REPORT,
FEB. 1973
160 * KLAPATCH R.D. + G,E. VITTI, 'GAS TURBINE COMBUSTOR TEST RESULTS AND
COMBINED CYCLE SYSTEM,* COMBUSTION, APRIL, 1971, PP.' ss-se
169 * KNOWLTON, T. M,, IGT/ 'HIGH.PRESSURE FLUIDIZATION CHARACTERISTICS OF
SEVERAL PARTICULATE SOLIDSi PRIMARILY COAL AND COAL-DERIVED MATERIALS),
67TH ANNUAL MEETING OF THE AMERICAN INSTITUTE OF CHEMICAL ENGINEERS, DEC.
197«
170 ft KRIEB, K.H., 'COMBINED GAS-AMD STEAM-TURBINE PROCESS WITH LURGI COAL
PRESSURE GASIFICATION,' CLEAN FUELS FROM COAL* SEPT 1973.
171 ft KYDD* PAUL H(, 'THE GEGAS PROCESSt, GENERAL ELECTRIC COMPANY.CORPORATE
R+D, SCHENECTADY, NEN YORK
172 ft LAROSA, P., * R.J. MCGARVEY, 'FUEL GAS FROM MOLTEN IRON COAL GASIFICA-
TION,' CLEAN FUELS FROM COAL* SEpT 1973,
173 * LEE, A. L., IMETHANATION FOR COAL GASIFICATION'. CLEAN FUELS FROM COAL,
SEPT. 1973
PRODUCER*' US BUREAU OF MINES TPR 77, MARCH , 1974
174 ft LIBERATORS, ARTHUR J, AND GILLMORE, DONALD NM 'BEHAVIOR OF CAKING
COALS XN FIXED-BED GASIFIERS'* THE SECOND ANNUAL SYMPOSIUM COAL GASIFICA*
TION» LIQUEFACTION AND UTILIZATION, THE UNIVERSITY OF PITTSBURGH,
R-16
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AUGUST 5»7, 1975
175 * LOEDING, J.W., * J,G, PATEL, 'IGT(U-GAS) PROCESS,' PRESENTED AT 67TH
ANNUAL AICHE MEETING, DEC 1974,
* LOEDING* J.H,, «IGT U-GA3 (CLEAN UTILITY GAS) PROCESS,' CLEAN FUELS
FROM COAL, SEPT 1973,
177 * LOEDING, J.W. AND PATEL, J(G., 'COAL GASIFICATION REVIEW,' 1975
JOINT POWER GENERATION CONFERENCE
178 * LORAN, B.I., ET AL,, 'GASEOUS ENVIRONMENTAL FACTORS IN COAL PYRQL-
YSI8 PLANT DESIGN,' 1975 JOINT PO*£R GENERATION CONFERENCE, A3ME NO.
75-PWR.3.
179 * LORENZJ, L,i JR.r 'ENVIRONMENTAL CONSIDERATIONS IN COAL CONVERSION
PROCESSES', SECOND ANNUAL SYMPOSIUM ON COAL GASIFICATION, LIQUEFACTION, AND
UTILIZATION! BEST PROSPECTS FOR COMMERCIALIZATION, UNIV. OF PGH. AUG. 1975
180 * MACNAB, A. J,, 'DESIGN AND MATERIALS REQUIREMENTS FOR HIGH BTU COAL
GASIFICATION', METALLURGY GROUP, C, F. BRAUN t CO,
iBi * MAGEE, E. M., ET AL, 'EVALUATION OF POLLUTION CONTROL IN FOSSIL FUEL
CONVERSION PROCESSES', EPA.650/2-74-009A, JANUARY 1974
182 * MARTIN, G.B,, 'ENVIRONMENTAL CONSIDERATIONS IN THE USE OF ALTERNATE
CLEAN FUELS IN STATIONARY COMBUSTION PROCESSES', IN EPA-650/2-7U-118
183 * MCGLAMERY, G. G., ET AL, 'DETAILED COST ESTIMATES FOR ADVANCED EFFLUENT
DE8ULFURIZATION PROCESSES', EPA-600/2-75-006, JAN, 1975
184 * HCIVER, ALAN E,, 'SASOLl PROCESSING COAL INTO FUELS AND CHEMICALS FOR
THE SOUTH AFRICAN COAL, OIL AND GAS CORPORATION', SECOND ANNUAL SYMPOSIUM
ON COAL GASIFICATION, LIQUEFACTION, AND UTILIZATION, AUGUST 5-7, 1975
185 * MCMATH, H, G,, ET AL, 'COAL PROCESSING! A PYROLYSIS REACTOR FOR COAL
GASIFICATION', CHEMICAL ENGINEERING PROGRESS, JUNE 1974, PP. 72-73
186 * MERRILL, R.C., ET AL, 'THE PRODUCTION OF CLEAN FUELS FROM EASTERN COALS
BY THE COED PROCESS,I PRESENTED AT 79TH AICHE MEETING, MARCH 1975.
187 * MEYERS, R.A., 'DESULFURIZATlQN OF COAL UTILIZING FERRIC SULFATE AND
OXYGEN*, SECOND ANNUAL SYMPOSIUM ON COAL GASIFICATION AND LIQUEFACTION,
AUGUST 5-7, 1975
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* MEYERS, R,A,, ET AI, 'CHEMICAL REMOVAL op NITROGEN AND ORGANIC SULFUR
PROM COAL*, NTIS P8»204 863, HAY la, 1971
169 • MIDDLETON, A,J, AND STOKES, C.A., »THE MANUFACTURE OF INDUSTRIAL rueu
GAS FROM COAL ON SMALL SCALES THE SECOND ANNUAL SYMPOSIUM COAL GASIFICA-
TION, LIQUEFACTION AND UTILIZATION, THE UNIVERSITY OF PITTSBURGH,
AUBU8T 5»7, 1975
190 * MITSAK, D, M,, ET AL* 'ECONOMICS OF THE K-T PROCE8SS KOPPERS CO,, INC.
AUGUST 6, i97«
I9i * MITSAK, D, MICHAEL AND KAMQDY* JOHN p.. »KOPPERS-TOTZEKI TAKE A LONG
HARD LOOK', SECOND ANNUAL. SYMPOSIUM COAL GASIFICATION, LI8UEFACTION AND
UTILIZATION, AUGUST S»7, 1975
192 ft MOE, J.M,, ISNG FROM COAL VIA THE LURGI GASIFICATION PROCESS.» CLEAN
FUELS FROM COAL* SEPT 1973
193 * MONTGOMERY, W,0, AND LEMEZIB, S,, UN ADVANCED COAL GASIFICATION
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197 * MYERS* RICHARD* (NEEDED FOR SYNTHETIC FUEL0I GOOD LUCK AND GOVERN-
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199 ft NAILL* ROGER F,, ET AL*
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201 * OSBORN, ELBURT F., 'COAL AND THE PRESENT ENERGY SITUATION', SCIENCE*
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206 * PATTERSON, R.C., 'THE COMBUSTION ENGINEERING COAL GASIFICATION
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R-19
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214 * PILL8BURY, P.M., U MICH PRESSURE COAL GAS COMBUSTOR TESTING PROGRAM,
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228 * SCHORA, F.C., ET AL, 'THE HYGAS PROCESS", CLEAN FUELS FROM COAL,
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229 * SCHORA, P.C., 'PROGRESS IN THE HYGAS PROCESS,' PRESENTED AT THE 79TH
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230 * SCHORA, F,C,, 'TECHNICAL AND HISTORICAL BACKGROUND', CLEAN FUELS FROM
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232 * SCHREIBER,R.J,, ET AL, ' BOILER MODIFICATION COST SURVEY FOR SULFUR
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233 * SCHRIDER, L, A, AND JENNINGS, j. w,, IAN UNDERGROUND COAL GASIFICATION
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236 * SHAN, H. AND MAGEE, E, M., 'EVALUATION OF POLLUTION CONTROL IN FOSSIL
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238 * SHEARER, H.A, AND CONN, A,L., 'ECONOMIC EVALUATION OF COED PROCESS
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241 * SHORE, D,, ET AL, 'EVALUATION OF R+D INVESTMENT ALTERNATIVES FOR SOX
R-21
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242 * SIEGEL,H,M,, AND T, KALINA, 'TECHNOLOGY AND COST OF COAL GASIFICA-
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253 * THROSEN, D. R., 'THE SEVEN YEAR SURGE IN THE CE COST INDEXES'* CHEMICAL
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R-22
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255 * TORKAS, T., AND LEWIS, p., u PICTORIAL TOUR OF THE SYNTHANE PILOT
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256 * TSAR03, C.L., ET AL,» 'PROCESS DESIGN AND COST ESTIMATE FOR PRODUC-
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R-23
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R-24
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APPENDIX A
METRIC SYSTEM CONVERSION FACTORS
Although EPA's policy is to use the metric system in all of its documentation, certain non-
metric units are used in this report for convenience. Readers more familiar with the metric system
may use the following to convert to that system:
Non-Metric Unit
in
ft
ft2
ft3
gal.
Ib.
ton
centistoke
°F
Btu
Btu/ft3
Multiplied By
2.540
0.3048
9.3 x 10'2
28.317
3.785
0.454
907.185
10~6
5/9(°F-32)
1.055 x 103
37.256
Yields Metric Unit
cm
m
m2
liter
1 i ter
kg
kg
m2/sec
°C
joule
joule/liter
A-l
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/2-76-052
2.
3. RECIPIENT'S ACCESSIOWNO.
4. TITLE AND SUBTITLE
Impact of Clean Fuels Combustion on Primary
Particulate Emissions from Stationary Sources
6. REPORT DATE
March 1976
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
J. Ferrell and G. Poe
8. PERFORMING ORGANIZATION REPORT NO.
AEROTHERM FINAL 75-175
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Aerotherm/Acurex Corporation
485 Clyde Avenue
Mountain View, California 94042
10. PROGRAM ELEMENT NO.
1AB012; ROAP 21ADK-004
11. CONTRACT/GRANT NO.
68-02-1318, Task 17
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final: 3-9/75
14. SPONSORING AGENCY CODE
EPA-ORD
is.SUPPLEMENTARY NOTESEPA project officer for this document is G. L. Johnson, mail
drop 63, Ext 2815.
16. ABSTRACT
The report gives results of an examination of various coal conversion
processes proposed for sulfur removal, to determine the implications for particulate
removal requirements when the converted fuels are burned. A substantial increase
in the near future is foreseen for the use of high-sulfur coal for large scale steam
raising. A major reduction in SO2 emissions from those sources will be required to
meet state and federal standards, either by desulfurizing the fuel or by removing
SO2 from the flue gas. Limited information is available on the combustion of
synthetic fuels but, based on the data obtained and the nature of the fuels, little
problem is foreseen in meeting effluent requirements for particulates. Other factors
upstream of the combustion of those fuels (e.g., turbine blade erosion or methanation
catalyst poisoning) seem more likely to determine particulate removal requirements.
The costs of sulfur removal by flue gas desulfurization (FGD) were examined briefly.
The cost savings potentially obtained by elimination of effluent particulate control
systems withsynthetic fuels were insignificant in affecting the substantial cost
advantage of FGD versus fuel conversion.
17.
KEY WORDS AND DOCUMENT ANALYSIS
a.
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Combustion
Coal
Coal Gasification
Coal Preparation
Sulfur Oxides
Dust
Desulfurization
Flue Gases
Fuels
Air Pollution Control
Stationary Sources
Particulate
Synthetic Fuels
Clean Fuels
Fuel Conversion
3B
21B
21D
13H
081
07B
11G
07A,07D
18. DISTRIBUTION STATEMENT
UnlinntPd
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
77
20. SFCURITY CLAPS tTliit na"cl
Unclassified
27. PRICE
EPA Form 2220-1 (9-73)
F-l
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